The Cost of UK Gas Security

Why It Matters

Securing gas supply during extreme events carries significant financial and carbon costs, shaping future UK energy policy and investment priorities.

Key Takeaways

• LNG imports will rise as UKCS output falls sharply
• New compressors needed for south‑to‑north gas flow reversal
• Biomethane could supply up to 10% of gas by 2030
• Demand‑side response cuts peak load, saving billions annually
• Maximising linepack improves resilience without extra LNG terminals

Pulse Analysis

The Department for Energy Security and Net Zero’s recent consultation underscores anxiety over the United Kingdom’s ability to keep the gas network running during extreme weather or supply shocks. A ‘rare‑scenario’ such as the 2016 Beast from the East cost the economy roughly £1 billion per day, and future modelling assumes a similar single‑day loss of the largest supply source. With the UK Continental Shelf’s output projected to fall by 12 % annually, the share of imported liquefied natural gas (LNG) is set to increase. However, the existing pipeline layout routes gas north‑to‑south, meaning that a surge of LNG arriving at southern terminals would require new compressors and reverse‑flow capacity.

Policymakers are therefore looking beyond pipework to meet resilience targets. The RI‑IO‑3 price control earmarks £14.6 bn for gas‑distribution upgrades, including line‑pack optimisation that stores gas in pipelines ahead of cold fronts. Simultaneously, the electricity sector is unlocking demand‑side response from large data centres and industrial loads, a strategy that cut peak demand by more than 5 % during the 2025 Texas heat wave and could shave billions from constraint payments. Domestic biomethane production, currently around 1 % of gas use, has a technical potential of up to 120 TWh, offering a low‑carbon supplement that reduces reliance on imported LNG.

The convergence of these measures creates a strategic choice for the UK: invest heavily in new LNG import terminals and associated infrastructure, or accelerate a shift toward distributed electricity, storage, and low‑carbon gases. Each option carries distinct financial and environmental trade‑offs; LNG imports carry a carbon intensity up to ten times that of North Sea gas, while expanding biomethane and line‑pack can preserve the network’s 99.9 % reliability record without adding emissions. Decision‑makers must weigh the £8 bn‑plus annual cost of constrained generation against the £14.6 bn distribution programme, ensuring that security of supply does not come at the expense of the UK’s net‑zero ambitions.

The Cost of UK Gas Security

Melissa Stark · RUSI Senior Associate Fellow, Energy and 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 £1 bn / 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.

Current supply mix

• UK Continental Shelf (UKCS) – 43 %

• Norwegian Continental Shelf (NCS) – 35 %

• LNG imports – 21 %

• 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 (e.g., 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. The emissions footprint of imported LNG (70–90 kg CO₂e/boe) is 3‑10 × higher than natural gas from UKCS (28 kg CO₂e/boe) or NCS (8 kg CO₂e/boe).

“Maximising the volume and flexibility of gas stored in the network, and packing the system ahead of a cold front will increase the ability of the local gas distribution operators to manage scarcity of supply during the ‘rare scenarios’.”

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More aggressive shifting of large data‑centre and industrial electricity loads

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 (payments to wind farms to reduce output) from what could be £8 bn annually by 2030 to approximately £3 bn.

During the Texas summer heat waves in 2024 and 2025, load flexibility proved effective. In summer 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 gives ERCOT authority to manage large electrical loads during grid‑stress events, requiring large loads to disclose behind‑the‑meter (BTM) and back‑up generation and allowing ERCOT to trigger emergency curtailments or backup generation.

During a “rare scenario”, large data‑centre and industrial loads could be instructed to reduce loads and/or move to BTM or back‑up generation to reduce natural‑gas demand.

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Increase local gas storage and supply to improve resiliency

The RIIO‑3 determination includes £14.6 bn investment in gas‑distribution infrastructure to ensure a safe and resilient network that can meet its 1‑in‑20 peak‑demand obligations. Linepack – the gas stored in the network’s pipes – can be maximised and the system “packed” (injecting more gas than is withdrawn) ahead of a cold front, increasing the ability of local gas distribution operators to manage scarcity.

RIIO‑3 already includes provisions for gas‑distribution reinforcements (pipelines, compressors, pressure management, storage and NTS offtake metering for low flow) to handle varying flow patterns and to help manage the injection of biomethane into the distribution network.

Biomethane potential

In 2024 the UK produced ~33 TWh (gross energy content) of biogas from sewage sludge, landfill gas, food‑waste digestion and agricultural residues. Of this, ~8 TWh was upgraded to biomethane and injected into the gas grid (just over 1 % of gas consumed), while ~25 TWh was used on‑site (≈4 % of consumption). Recent reports estimate the UK’s biomethane potential at 40‑60 TWh (Regen) to 120 TWh (Cadent).

Internationally, California’s Senate Bill 1440 sets a medium‑term goal for utilities to replace ~12.2 % of their “core” gas demand with biomethane by 2030, and the EU’s biomethane target is ~10 % of core gas consumption.

During the 2018 “Beast from the East”, national gas demand rose by 55 % but the reliability of the gas network remained at 99.9 %. Maximised linepack and local biomethane production are additional tools that Gas Distribution Networks (GDNs) can use to reduce imported LNG volumes.

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Increase use of distributed electricity resources

During Hurricane Melissa in Jamaica, solar power withstood the storm and provided critical electricity. The UK’s Clean Power Action Plan aims for ~45 GW of solar capacity by 2030. Although solar output is lower in winter, coupling solar with batteries, microgrids and small combined‑heat‑and‑power (CHP) units can contribute to resiliency.

In New Mexico, Kit Carson Electric Cooperative is building three microgrids to increase resilience during wildfires and extreme weather, achieving 100 % daytime solar in 2022. Colorado’s House Bill 22‑1249 requires a roadmap for grid resilience that emphasises microgrids, and China’s National Energy Agency has released an action plan for high‑quality distribution‑grid development focused on disaster resilience.

“If the UK North Sea industry believes that applying technology innovation to tie‑backs and marginal fields can slow the decline of the UKCS, then this should be explored.”

The discussions for the RIIO‑3 Electricity Distribution price control (effective April 2028) provide an optimal opportunity to explore the role of distribution network operators during “rare scenarios”.

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Nurture existing UKCS and NCS infrastructure

DESNZ and NESO reference the North Sea Transition Authority (NSTA) assessment that gas production from the UKCS is decreasing at 12 % per year, implying a sharp drop in the UKCS share of supply from today’s 43 %. Offshore Energy UK (OEUK) argues that the 12 % decline is a policy choice, not a geological reality, and that much more can be produced from the UKCS than NSTA estimates.

The Norwegian Continental Shelf (NCS) also faces decline, but Norway’s Offshore Directorate (NOD) challenges its industry to reverse the trend, highlighting the potential for “satellite” discoveries tied back to existing infrastructure.

If the UK North Sea industry believes that applying technology innovation to tie‑backs and marginal fields can slow the decline of the UKCS (with emissions of 6‑12 kg CO₂e/boe for platforms <10 years old versus 70‑90 kg CO₂e/boe for imported LNG), then this should be explored. Utilising UKCS and NCS gas resources will likely need investment in gas storage to provide ramp‑up supply for “rare scenarios”.

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Conclusion

LNG is important, but if the UK leans into the future distributed electricity system 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.