The Cost of UK Gas Security

The Department for Energy Security and Net Zero’s (DESNZ) recently released UK Gas Systems in Transition: Security of Supply consultation and the National Energy System Operator’s (NESO) Gas Supply Security Assessment. Both tackle the UK’s dependence on natural gas for energy security during ‘rare scenarios’ that consider how the gas system would function on the coldest single day in the last 20 years if the single biggest source of gas supply was lost due to an unprecedented infrastructure failure, for example due to weather or sabotage/attack.

Preparing for rare scenarios is critical: estimates of the cost to the UK of ‘the Beast from the East’ in 2016 (extreme weather combined with infrastructure failures that lasted about a week) was around £1bn/day due to high energy costs and lost economic output. Rare scenario performance is also one of the key benchmarks for energy system resilience.

Both documents argue that our future energy security strategy will depend more on imported LNG and that investment will be needed in infrastructure to increase capacity and accommodate changing flows. The need for additional investment is driven by gas demand for energy security during rare events, not by everyday usage: Between 2024-2050, the NESO Future Energy Scenarios estimate annual demand for natural gas will decline by 40-75%, but demand for gas during ‘rare scenarios’ will fall much more slowly.

Currently, UK gas supply comes from the UK Continental Shelf (UKCS, 43%), Norwegian Continental Shelf (NCS, 35%), LNG imports (21%), and interconnector imports from Europe (1%). With the decline of the UKCS, the UK will require more LNG imports, and, with the growth of the global LNG market, there will be ample supply. But increased LNG imports would require new infrastructure because although the UK has the second largest LNG infrastructure in Europe, the flow of gas would change. Currently gas pipelines run from UKCS and NCS in the north to the south. If more gas comes from LNG terminals in England and Wales, flow would move from south to north, requiring new compressors and more capacity. DESNZ and NESO acknowledge that the commercial viability of this infrastructure is challenging, given the decline in gas volumes.

History has shown that the global LNG market responds effectively to crises (for example, Fukushima, Russia’s invasion of Ukraine, winter storm Elliott), but during a ‘rare scenario’, the UK would be a price-taker, and LNG prices are likely to be high. Additionally, the cost of keeping gas infrastructure running increases when capacity is not being fully utilised, potentially requiring financial support for infrastructure owners. There is the added complication that the emissions footprint of imported LNG (70–90 kgCO2e/boe) is 3-10x higher than natural gas from UKCS (28kgCO2e/boe) or NCS (8kgCO2e/boe).

But as the energy system becomes more electric and distributed, the UK can leverage the characteristics of the system its building to maximise use of the natural gas infrastructure it has.

More aggressive shifting of large data centre and industrial electricity loads and use of behind-the-meter generation during the ‘rare scenarios’

The RIIO-3 Final Determinations for Electricity Transmission already structure the connection of large electricity loads – such as industry hubs, data centres, and AI zones – as strategic assets capable of providing demand-side response (DSR), to manage consumption during high-stress periods. This flexibility is a cornerstone of the framework's goal to reduce constraint costs (costs incurred when transmission capacity is not available, for example, payments to windfarms to reduce output) from what could be £8 billion annually by 2030 to approximately £3 billion.

During the Texas summer heat waves in 2024 and 2025, load flexibility proved to be an effective tool. In the summer of 2025, total peak load was reduced by more than 5% through reductions in loads from cryptomining and industrial facilities (~4.7 GW). Texas’ Senate Bill 6 goes further and grants ERCOT, the system operator of Texas’ electricity grid, the authority to manage large electrical loads during periods of grid stress, particularly those caused by extreme weather events. Large loads are required to disclose to ERCOT behind-the-meter (BTM) and back-up generation. SB6 gives ERCOT an emergency trigger: during an energy emergency and after exhausting other market tools, ERCOT can direct the facility to activate backup generation or curtail reduce energy consumption. SB6 also requires ERCOT to develop a reliability service to competitively procure demand reductions from large loads in advance of an anticipated energy emergency alert event. Despite these emergency measures, Texas continues to be one of the biggest data centre markets in the world with over 164 GW in projects (almost 73% of the large loads in ERCOT’s queue), with an increasing number of these projects including co-located generation.

During a ‘rare scenario’, large data centre and industrial loads could be instructed to reduce loads and/or move to behind-the-meter or back-up generation to reduce natural gas demand.

Increase Local Gas Storage and Supply to Improve Local Resiliency During ‘Rare Scenarios’

The RIIO-3 determination includes £14.6bn investment in the gas distribution infrastructure to ensure a safe and resilient network that can meet its 1-in-20 peak demand obligations. Linepack is the gas stored in the network’s pipes. Maximising the volume and flexibility of gas stored in the network, and packing the system (injecting the system with more gas than is being withdrawn) ahead of a cold front will increase the ability of the local gas distribution operators to manage scarcity of supply during the ‘rare scenarios.’ RIIO-3 already includes provisions for gas distribution reinforcements and activities, including ‘pipelines, compressors, pressure management, storage and NTS offtake metering for low flow’ to ensure the network can handle varying flow patterns and to help manage the injection of biomethane into the distribution network.

Biomethane can also replace some LNG supply. In 2024, the UK produced ~33 TWh (gross energy content) of biogas from sewage sludge (methane captured from wastewater treatment), landfill gas (gas collected from decomposing waste in landfill sites), food waste (diverted municipal and commercial organic waste), and agricultural residues (animal manure, slurry and specific energy crops). Of the 33 TWh, ~8 TWh was upgraded to biomethane and injected into the gas grid (just over 1% of the gas consumed from the gas grid) and ~25 TWh of the biogas was used directly at the site of production (almost an additional 4% of gas consumption). Recent reports by Regen and Cadent estimates the biomethane potential to be 40-60 TWh and 120 TWh respectively.

In California, Senate Bill 1440 (SB 1440) sets a medium-term goal for utilities to replace approximately 12.2% of their ‘core’ gas demand with biomethane by 2030. The EU’s biomethane target is ~10% of its core gas consumption.

The UK’s Gas Distribution Networks (GDN) have experience managing ‘rare scenarios’. During the Beast from the East, national demand for gas increased by 55% but the reliability of the gas network remained at 99.9%. Maximised linepack and local biomethane production are additional tools that GDNs can use to reduce imported LNG volumes.

Increase use of Distributed Electricity Resources.

During Hurricane Melissa that hit Jamacia earlier this year, solar power withstood the storm and provided critical electricity. The UK’s Clean Power Action Plan has set an ambition of ~45 GW of solar capacity by 2030. Although, in winter, the season of the ‘rare scenario’, electricity production from solar on dark days will be much lower than the capacity available, when coupled with batteries, microgrids, and small CHPs, distributed resources could contribute to increased resiliency.

In New Mexico, Kit Carson Electric Cooperative (KCEC) is building three microgrids in targeted areas to increase resilience during wildfires and extreme weather events as part of the US Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) programme. Over the last ten years, KCEC has grown its solar and battery energy storage (BESS) capacity and achieved 100% daytime solar in 2022. KCEC continues to develop its capabilities to include microgrids, weather stations, AI Smart Edge devices, and real-time grid monitoring. Colorado House Bill 22-1249 requires the Colorado Energy Office to develop a comprehensive roadmap for improving grid resilience and reliability, with a specific focus on how microgrids can be used to harden the grid and provide autonomous power to communities during extreme weather or disasters. China’s National Energy Agency released an action plan for high-quality distribution grid development focused on enhancing the power supply capacity, disaster resilience and capacity of the distribution grid.

The discussions are happening now for the RIIO-3 for Electricity Distribution price control effective from April 2028, so it is an optimal opportunity to explore the role of distribution network operators/distribution system operators during ‘rare scenarios’.

Nurture Existing UKCS and NCS Infrastructure

In estimating available domestic supply, the DESNZ and NESO gas reports reference the North Sea Transition Authority (NSTA) assessment that gas production from the UKCS is decreasing at 12% per year, so the share of UKCS of UK supply will drop significantly from the 43% today. Offshore Energy UK (OEUK) published a report in June that argued that the 12% decline is a policy choice, not a geological reality, and that much more can be produced out of the UKCS than the NSTA estimates.

The Norwegian Continental Shelf provides 35% of UK gas supply but the NCS is also in decline. However, the equivalent of the NTSA in Norway, the Norwegian Offshore Directorate (NOD), ‘challenges’ its own industry to reverse the decline. Their 2024/2025 Resource Report explicitly states that ‘the greatest potential for value creation lies in producing more from existing fields and finding small "satellite" discoveries that can be tied back to current infrastructure before it is decommissioned’.

If the UK North Sea industry believes that applying technology innovation to tiebacks and marginal fields can slow the decline of the UKCS (with the added benefit of emissions 6-12kg CO2e/boe for platforms less than 10 years old compared to imported LNG emissions of 70–90 kgCO2e/boe), then this should be explored. It is important to note that utilising UKNS and NCS gas resources will likely need an investment in gas storage to provide ramp-up supply for the ‘rare scenario’.

In conclusion, LNG is important, but, if the UK leans into the future distributed electricity system that it is building, the investments it is making under RIIO-3, increasing domestic biomethane production and nurturing its existing gas infrastructure, it may be able to avoid (or at least reduce) additional investments in LNG import infrastructure.

© RUSI, 2026.

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