Westminster is advancing a suite of reforms aimed at decoupling UK wholesale electricity prices from the marginal cost of natural gas, a structural feature that has amplified household bills and weighed on industrial competitiveness. The proposed changes, combining market design, network policy and contract architecture, represent the most significant revisit of the electricity trading arrangements since privatisation.

Why gas still sets the price of British electricity

The United Kingdom's electricity market, run through a combination of half-hourly trading, capacity markets and bilateral contracts, continues to exhibit an uncomfortable feature: the marginal unit dispatched to balance demand is often a gas-fired combined cycle plant. Under a merit-order system in which all generators in a given period are paid the clearing price set by the most expensive dispatched unit, the result is that wholesale prices tend to move with natural gas prices even when the underlying generation mix is dominated by wind, nuclear and, at times, solar output. In periods of high gas prices, such as those following the invasion of Ukraine in 2022, consumers have seen bills rise sharply even as the technical cost of generation for much of the fleet has remained stable or declined.

The gap between the average cost of generation across the fleet and the marginal price received for electricity is not itself evidence of market failure. Marginal pricing is a feature of competitive wholesale markets around the world, and it delivers efficiency in dispatch and investment signalling. But the political and economic consequences of extreme marginal pricing have prompted Treasury, the Department for Energy Security and Net Zero, Ofgem and industry stakeholders to reconsider the institutional architecture. The question is not whether marginal pricing persists as a feature but whether adjustments can reduce its pass-through to consumers and industrial users without undermining investment incentives.

The policy ambition is reinforced by the long-term imperative to decarbonise. As the electricity system shifts towards low-marginal-cost renewables, a market design that routinely rewards fossil generation with rents derived from gas pricing dynamics looks increasingly anomalous. Reforming the market to capture the benefit of zero-marginal-cost generation for bill payers, while maintaining appropriate investment signals, is a defining policy problem of the coming decade.

The reform toolkit on the table

The Review of Electricity Market Arrangements, known as REMA, has laid out a menu of options that span marginal changes to the existing arrangements and more fundamental redesign. The most discussed interventions fall into four groups.

Contracts for Difference and long-term contracting

The Contracts for Difference regime has been the government's principal instrument for supporting new low-carbon generation since 2014. Under a CfD, generators are paid a strike price for their output, with the difference between the strike price and the reference wholesale price settled in either direction. The mechanism has successfully driven down the cost of offshore wind and other technologies through competitive auctions. Reforms under consideration include extending CfDs to existing assets through a voluntary opt-in, broadening the reference price used for settlement, and using CfDs as a route to deliver a direct consumer rebate when wholesale prices spike.

Locational pricing

Locational marginal pricing, also called zonal or nodal pricing, would replace the current single national wholesale price with prices that reflect the cost of serving demand in specific regions of the grid. Proponents argue that locational signals would incentivise generation to build where the grid can accommodate it, reduce the costs of constraint payments and accelerate demand-side flexibility at locations with abundant generation. Opponents highlight the risks to investor confidence, the complexity of implementation and potential impacts on consumer bills in regions with limited generation. The debate has become one of the most polarising in UK energy policy.

Capacity market and strategic reserves

The capacity market, which pays generators and demand-side providers a separate fee to be available during stress periods, is being revised to reflect changing system needs. The share of the capacity market filled by battery storage, demand-side response and low-carbon flexibility has grown, and further reforms to technical parameters and contract lengths are under discussion. Separately, the concept of a strategic reserve for specific purposes, including back-up during long duration low-wind periods, is being explored.

Network policy and connection reform

Network charging and connection arrangements are under review, with particular focus on reducing the delays currently affecting new generation and demand connection. A reformed queue management process, better coordination between transmission and distribution connections, and adjustments to the socialisation of network costs are each expected to feature in the package. Network policy is technically separate from wholesale market design but is functionally inseparable in its impact on both consumer bills and investment decisions.

The industrial angle: competitiveness and bills

Energy-intensive UK industries, including steel, chemicals, ceramics, glass and aluminium, have seen their international competitiveness materially eroded by the combination of high wholesale electricity prices, relatively high carbon price exposure and the indirect cost of renewable obligations flowed into bills. The British Ceramic Confederation, UK Steel, the Chemical Industries Association and other trade bodies have consistently called for structural reform to bring UK industrial electricity prices closer to those in competing jurisdictions, particularly France, Germany and the United States.

The British Industry Supercharger policy has provided targeted relief to the most energy-intensive industries through a combination of exemptions from network charges and policy costs, with additional support from the Network Charging Compensation Scheme. The measures have narrowed but not closed the competitiveness gap, and industrial users continue to advocate for more fundamental reform of both wholesale pricing and the charges levied on industrial consumers.

Household bill dynamics

For households, the price cap operated by Ofgem has become the dominant determinant of bill levels, with the cap itself driven primarily by wholesale market prices over a forward window. Reform of the wholesale market that reduces the pass-through of gas prices to the cap would therefore have direct household benefits. Complementary reforms to the structure of the cap, including the standing charge question and the consideration of social tariffs for vulnerable consumers, are ongoing but distinct from the REMA agenda.

Investor and developer perspectives

The investor community has mixed feelings about the reform agenda. Large developers of offshore wind and nuclear projects generally favour extensions of the CfD regime and other long-term contracting mechanisms that improve revenue visibility. Storage and flexibility providers welcome reforms that improve the remuneration of the services they provide. On the other hand, the possibility of locational pricing has introduced meaningful uncertainty into investment cases for projects in regions that might see prices diverge from the national average.

The UK's reputation for policy stability in the offshore wind sector, built over a decade of successive CfD allocation rounds, is a prized asset that developers and financiers are keen to protect. Recent auction rounds that failed to clear sufficient capacity provided a reminder that the interaction between reference prices, strike prices and market conditions can derail policy ambitions if not calibrated precisely. Subsequent adjustments have restored appetite, but the episode illustrated the importance of careful design in any reform package.

The gas-to-power transition

Gas generation remains essential for system reliability, particularly during low-wind periods in the winter. The reform package will need to ensure continued investment in flexible gas capacity, including some plants capable of converting to hydrogen over time, even as the share of their running hours in the system declines. The economics of such capacity depend heavily on capacity market revenues and on expected wholesale prices during the limited periods when they are dispatched. Investor appetite for new gas capacity has waned, and the policy framework will need to address this carefully.

Storage, demand flexibility and the system of the future

The transition to a cleaner electricity system depends on the build-out of storage and demand-side flexibility, not only generation. Battery storage has grown rapidly, with grid-connected projects routinely exceeding one hundred megawatts of capacity and durations extending beyond the two-hour standard that dominated early deployments. Pumped storage hydro, long-duration battery chemistries, flow batteries and compressed air energy storage are all being examined for their role in a system with high renewable penetration.

Demand-side flexibility, from industrial load shifting to electric vehicle smart charging and heat pump optimisation, holds substantial promise but requires market and regulatory arrangements that reward flexibility appropriately. Ofgem's design of the Balancing Mechanism, the Capacity Market and the rules governing aggregators directly affects the viability of flexible demand. Reform in this area is technically complex but commercially material, and it intersects with the broader market reform agenda in important ways.

Hydrogen and low-carbon fuels

Hydrogen production, storage and use in power generation is part of the long-term vision, though timelines and scale remain uncertain. Government support through the Hydrogen Business Model and infrastructure investment will shape the trajectory. In the near term, blending of hydrogen with natural gas is limited, but the prospect of hydrogen-fuelled gas turbines providing long-duration firm capacity in a future low-carbon system is a recurring theme in strategic modelling work by the Electricity System Operator.

Policy risks and timing

The biggest risk to the reform agenda is the pace of decision-making. REMA has been in consultation and analysis for several years, and each delay pushes both the benefits and the investment uncertainty further into the future. Developers are operating in an environment in which the rules governing revenue streams could change meaningfully, which can slow investment decisions at precisely the moment when acceleration is needed to meet clean power targets.

Political transitions are a further risk. The current policy trajectory broadly commands cross-party support for the decarbonisation objective, but disagreements persist on the pace of transition, the appropriate role of nuclear, the design of support mechanisms and the treatment of energy-intensive industries. The Office for Budget Responsibility, the Climate Change Committee and the National Infrastructure Commission each play advisory roles that shape the policy conversation, and their recommendations will influence the final shape of the reform package.

Outlook: a system in transition

The most likely reform path is a combination of targeted adjustments to CfDs, capacity market reform, more ambitious connection queue management, and a cautious approach to locational pricing that preserves investor confidence while capturing some of the efficiency benefits. Complete replacement of the current single-zone marginal pricing arrangement is unlikely in the short term, but a gradual evolution towards more granular price signals, combined with stronger long-term contracting, appears broadly consistent with both policy and market views.

For consumers and businesses, the implications of successful reform are significant. A future market in which wholesale prices more closely reflect the blended cost of a low-carbon fleet, rather than the marginal cost of imported gas, should deliver materially lower and more stable electricity prices over time. Achieving that outcome requires navigating a complex set of trade-offs, maintaining investor confidence and delivering on the build-out of both clean generation and the networks and flexibility that support it. The energy market reform package will be one of the defining economic policy projects of this Parliament, and its consequences will be felt across the FTSE, in rural communities hosting infrastructure, and in every household facing an electricity bill.