Since late February 2026, disruption to shipping through the Strait of Hormuz and damage to Qatar’s Ras Laffan liquified natural gas (LNG) export facilities have removed a significant share of global LNG supply from the market. The IEA’s Q2 2026 analysis indicates a reduction in Middle Eastern gas output and a cumulative loss of LNG supply over the 2026–2030 period.[1] The UK’s direct exposure to the Qatari supply loss is limited (Qatar accounted for just 1.9 per cent of UK gas imports in 2024, with Norway providing around 75 per cent via pipeline),[2] but the indirect exposure is substantial. As LNG cargoes are redirected towards the highest-priced markets, the marginal cost of supply into the UK rises even when physical volumes are not immediately constrained.
The April 2026 price cap fell by 6.6 per cent from the previous quarter, to a new level of £1,641per year, but this reflects the Government’s decision to remove green levies from household bills rather than any easing of wholesale market conditions. The price cap’s observation period had closed before the disruption to LNG supply; wholesale price increases since then are expected to feed through to retail bills from July 2026 and are likely to persist into winter. The summer injection window, the low demand period in which gas can be diverted into storage, is the most effective point at which intervention can reduce the impact ahead of peak winter demand.
Absent intervention from the Government, price-based rationing will allocate energy according to ability to pay domestically, concentrating the burden of shortages on low-income households and smaller businesses while generating windfall returns for producers, and internationally, directing supply toward whichever countries can pay the most.
This crisis reaches the UK at a moment of structural vulnerability:
As a gas import-dependent nation, the UK cannot fully isolate itself from global market conditions. But the frequency with which expensive LNG imports set the marginal price can be reduced, though the mechanisms differ between the gas and electricity markets. In the gas market, LNG imports set the NBP wholesale price, directly affecting heating and industrial costs; in the electricity market, gas-fired generation sets the marginal price, transmitting those costs into electricity bills.
Britain’s wholesale electricity market clears at a single price in each half-hour period, set by the last and most expensive unit required to meet demand, almost always a gas-fired generator. All generators, including those with production costs far below market prices, receive this gas-set price, creating a persistent divergence between cost and price, borne by consumers and captured by generators as windfall returns.
The same logic applies to gas markets. LNG, as the highest-cost source of supply, frequently sets the NBP wholesale price. Domestic producers, whose costs are far below LNG, receive the inflated price for every unit they sell, creating a perverse incentive, whereby greater import dependency increases producer returns at the direct expense of consumers.
Gas storage illustrates the problem. Storage provides system-wide insurance value, reducing the frequency with which expensive LNG sets the marginal price. However, the commercial model for private storage operators depends entirely on the seasonal spread, buying cheap in summer and selling dear in winter. The system-wide benefit of storage is precisely the compression of that spread, which constitutes a direct loss to the operator who invested in it. Private operators therefore have no commercial incentive to invest beyond what that spread can support, and an incentive to manage withdrawal rates to maximise rather than moderate it. This has resulted in chronic underinvestment.[5]
Previous responses, such as, in 2022, the £23 billion Energy Price Guarantee, compensated consumers for high prices without altering the mechanisms that produced the high prices. This compounded the problem by subsidising demand rather than reducing it, and prevented the downward demand adjustment that might have alleviated pressure on prices. The approach set out here operates on those causal mechanisms directly and is designed to build the institutional foundations for their longer-term replacement with a single buyer model.[6]
Four mutually reinforcing instruments make possible, at a national level, a shift from passive exposure to active management of supply, demand and price formation during crisis periods.
These are:
Gas produced from the UKCS is transported via offshore pipelines to onshore terminals. Shippers nominate flows into the National Transmission System and determine whether gas is sold domestically or exported via the Bacton interconnectors to continental Europe. In summer months, when domestic demand is low, the arbitrage incentive to export is strongest. At this point, suppressing export flows has the greatest effect: it allows NBP to fall below TTF, temporarily suppressing Britain’s gas prices below continental market levels. The UK can exploit the injection window not just to fill storage, but to run on cheaper domestically priced gas.
An export levy is applied to gas flowing through the Bacton interconnectors in the export direction, charged to the responsible shipper. Calibrated to the Dutch TTF day-ahead price, the levy activates when TTF exceeds 80p/therm and is set at 40 per cent of the excess above that threshold, reducing the net return from export and retaining a greater share of supply within Britain’s gas transmission system. A full export ban would achieve more direct supply allocation but risks breaching UK trade commitments; the levy achieves the same objective through price signals rather than direct prohibition and is designed to remain within existing trade obligations.
The complementary Import Attraction Mechanism (IAM) ensures the levy never renders the UK uncompetitive as an import destination when additional supply is needed. When activated (based on forward monitoring of storage levels and seasonal trajectories) it pays a spread-linked subsidy to shippers nominating pipeline gas or LNG into the national system. The subsidy rate mirrors the levy rate, compensating importers for the suppression of NBP relative to TTF that the levy causes.
The Government should create a publicly owned strategic gas reserve through acquisition of the Rough storage facility from Centrica, or through public funding of its redevelopment with a majority public ownership stake.[7] Rough is Britain’s largest storage site, currently providing half of national storage capacity. Public ownership would allow the Government to set and manage strategic fill targets, prioritising summer injection regardless of short-term commercial signals.
Centrica has indicated that full redevelopment of Rough, which it cannot fund without a regulatory model,[8] would significantly expand capacity beyond its current 1.5 bcm. Bringing the facility into public ownership now ensures that redevelopment is pursued in line with system objectives and at a pace determined by national need rather than commercial viability. Acquisition cost is expected to be well below Centrica’s stated £2 billion redevelopment figure, which reflects forward capital expenditure rather than current asset value.
A standing offer of a guaranteed domestic offtake contract should be made to UKCS producers at a price that reflects operating and maintenance costs. This stabilises production in alignment with long-term falling demand by supporting maintenance investment, while delivering a direct price benefit to consumers. Contracted volumes are delivered into the national transmission system year-round, injected into the strategic reserve where capacity allows, and allocated proportionally to suppliers at the contract price. Allowing a disorderly decline does not lead to a cleaner transition, but instead to greater dependency on higher-carbon LNG imports and greater exposure to global price volatility.
While the gas instruments in the preceding sections reduce the wholesale gas price that feeds into electricity costs, the BAM acts on the electricity pricing mechanism itself. The BAM removes a defined and growing share of low carbon generation from wholesale marginal pricing. The Government offers contracts at fixed prices, indicatively £50–60/MWh and commits to purchasing generation to meet an allocated share of demand through a standing offer to eligible generators. Contracted generation is allocated to retail suppliers at these prices, bypassing the wholesale market for that share of supply. The result is a blended effective price that falls as BAM coverage increases.
[.fig]Table 1: Illustrative blended electricity price at different BAM coverage levels measured as a percentage of demand[.fig]
[.notes]Notes: These figures are illustrative; final impacts depend on realised wholesale prices and contract terms.[.notes]
Unlike existing Contracts for Difference (CfDs), which operate as a separate settlement mechanism without altering the wholesale price at which electricity is bought and sold, the BAM removes contracted generation from wholesale price formation entirely. Pass-through to consumers is ensured through the existing Ofgem price cap methodology. Implementation would require either extending the powers of the LCCC or Great British Energy (GBE) through secondary legislation or establishing a dedicated counterparty function within an existing public body.
The BAM’s voluntary design is deliberate. In a crisis period, forcing generators to sell outside the wholesale market at fixed prices would face significant legal and industry resistance; a standing offer at cost-reflective prices is commercially attractive to generators already exposed to wholesale price volatility, particularly in the context of export levies. As coverage expands, the marginal market shrinks and the institutional machinery for centralised procurement matures, progressively closing the distance to a fully centralised single buyer model.[9]
Demand reduction reduces the volume of gas the UK needs to import, directly reinforcing the export levy, the strategic reserve and the BAM. This includes both direct reductions in gas consumption and the flexibilisation of electricity demand to match low-carbon supply availability, reducing reliance on gas-fired peak generation. In the longer term, it creates the conditions under which domestic production can decline in an orderly way rather than contracting faster than the economy can absorb.
Immediate measures include a statutory cap on heating temperatures in commercial premises, and a public campaign on domestic thermostat reduction can deliver material reductions in gas consumption within the current winter period. An expanded Demand Flexibility Service (DFS) can complement these by incentivising shifts in electricity consumption away from peak periods, reducing reliance on gas-fired peak generation. France reduced gas consumption by approximately 17 per cent over a single winter through a comparable package of “energy sobriety” measures in 2022.[10] These are fast-acting instruments that reduce the volume around which the supply-side measures must operate.
Structural measures include a national home insulation programme prioritising fuel-poor and medically vulnerable households,[11] accelerated heat pump deployment and completion of the smart metre rollout[12] to reduce gas demand on a sustained basis as well as bringing forward legislation to require landlords to meet minimum EPC “C” standards before renewing tenancies.
The instruments are designed to reinforce one another. A lower NBP price from the offtake contract reduces the frequency of IAM activation. A fuller strategic reserve reduces peak winter reliance on LNG. Higher BAM coverage shrinks the residual wholesale market. Demand reduction lowers the total volume around which all of this operates, and, unlike the £23 billion Energy Price Guarantee, which compensated consumers for high prices without altering the marginal pricing mechanisms that produced them, this package operates directly on those mechanisms.
This approach supports distributional justice — where windfall returns are capturable, through export arbitrage on gas and marginal pricing on electricity, these measures transfer that value directly to consumers. Where the UK is import-dependent, the government bears the cost of securing supply on behalf of consumers rather than leaving them exposed to global market prices.
Secondly, it assists the green transition, because managing the decline of domestic production in alignment with falling demand avoids greater dependency on higher-carbon LNG imports. The proposal is, therefore, consistent with decarbonisation.
Additionally, it builds institutional capacity, as each instrument builds capability for longer-term reform. The strategic reserve establishes a national energy asset. The offtake contract demonstrates the state as a credible principal purchaser of energy, a role absent since the nationalised British Gas Corporation in the 1970s. The BAM develops the procurement and allocation functions required for comprehensive electricity market reform. In this way, the present crisis creates the political window to build what should have been built years ago.
The summer of 2026 is the only window in which storage can be increased, BAM contracts established, and supply-side measures put in place ahead of peak winter demand. A delayed response would leave the UK exposed to whatever global LNG market conditions emerge during the coming autumn and winter. Even if disruption to Strait of Hormuz shipping ends or partially stops, the underlying constraints on LNG supply are likely to persist and the structural vulnerabilities this crisis has exposed (inadequate storage, marginal pricing and LNG dependence) remain. Uncertainty about the severity and the duration of the disruption is itself an argument for fast action. The available policy window is time-limited, and the costs of inaction are likely to be higher and more difficult to reverse than the risks associated with intervention.
This briefing draws on a longer report, Patricia Pino, "From Price Taker to Price Shaper: A Time-Critical Plan for UK Energy Prices and Security", 2026. Available here.
[1] “Gas Market Report, Q2-2026”, International Energy Agency, 2026. Available here.
[2] Department for Energy Security and Net Zero, “Digest of UK Energy Statistics” (DUKES), Table 4.3, DESNZ, 2025. Available here.
[3] Energy UK, “The role of gas storage in ensuring energy security”, Energy UK, 2025. Available here. NB. The gas and electricity market mechanisms described in this paper operate within Great Britain. Northern Ireland and the Republic of Ireland share separate gas and electricity market arrangements and are, therefore, outside the direct scope of the proposals set out here. Northern Ireland would nonetheless be indirectly affected by both the current supply shock, given its dependence on GB gas supply via the Moffat interconnector, and by any measures that alter GB wholesale gas prices, which feed through via that connection. The Moffat interconnector is explicitly excluded from the export levy to protect the gas supply of both Northern Ireland and the Republic of Ireland.
[4] National Gas Transmission, “Gas System Status Data Portal”. Available here.
[5] Chris Le Fevre, “Gas Storage in Great Britain”, Oxford Institute for Energy Studies, 2013. Available here.
[6] Donal Brown and Matthew Lockwood, “Policy Options to Reduce Electricity Bills in Great Britain”, UCL Institute forInnovation and Public Purpose, 2026. Available here.
[7] The strategic gas reserve proposed here refers to a physical buffer stock of gas held in storage, distinct from proposals for a strategic reserve of electricity-generating capacity (typically mothballed gas turbines held outside the market as a backstop against generation shortfalls).
[8] “Perfect storm reduces UK winter gas storage to ‘concerningly low’ levels”, Centrica, 2025. Available here.
[9] Donal Brown, “Crude Awakening: Averting the Unfolding Energy Crisis”, Common Wealth, 2026. Available here.
[10] Ariane Millot and Steve Pye, “France used 10% less electricity last winter: three valuable lessons in fighting climate change”, The Conversation, 18 September 2023. Available here.
[11] Madeleine Pauker, Donal Brown, “A Plan for Places”, Common Wealth, 2026. Available here.
[12] Stephen Hall, “Retail Reimagined: How Regional Energy Boards Could Deliver a Fair and Flexible Energy System”, Common Wealth, 2026. Available here.