REMA Summer Update: Zonal Pricing Out, Reformed National Pricing In

The REMA-mill ends with DESNZ’s decision on electricity market reforms and the rejection of Zonal Pricing after extensive industry consultation.

As widely anticipated, on 10^th July 2025, the Department for Energy Security & Net Zero (DESNZ) released its Summer Update on the Review of Electricity Market Arrangements (REMA).

The update is significant for its affirmation of a single national wholesale electricity market and therefore its decision to reject zonal pricing, following what has been an extensive and at times fevered industry-wide debate. DESNZ states that this policy decision is intended to streamline network planning, whilst maintaining investor confidence a fair energy system, optimise infrastructure investments, and support the United Kingdom’s ambition to achieve a reliable, decarbonised power system.

The Summer Update also outlines the direction of transmission upgrades, connection charges, and operational procedures that will likely shape investment decisions in the UK power sector in the years to come.

The REMA programme, established in 2022, was designed to ensure that the UK’s electricity market arrangements are fit for a future dominated by clean, renewable and homegrown energy. The government’s clean energy superpower mission aims to deliver clean power by 2030 and accelerate the transition to net zero across the economy.

See our previous CMS updates on REMA:

• REMA Autumn Update: Key Decisions and Market Reforms
• Winter Update on the TM04++ and wider electricity connection and network reforms in the Great Britain electricity market
• REMAking the GB Electricity Market – new consultation published

The policies that form part of the reformed national pricing package:

Source: REMA Summer Update, DESNZ

Rejection of Zonal Pricing

The most anticipated, and heavily trailed, announcement in the Summer Update is the government’s decision not to implement zonal pricing. After extensive evaluation and industry consultation, DESNZ concluded that the complexity and uncertainty generated by creating separate pricing zones could undermine critical areas of the electricity market. Under a zonal system, wholesale costs would vary region by region, posing several potential challenges for DESNZ including:

1. Investor Uncertainty on implementation: The process of implementing zonal pricing would introduce significant risk regarding price signals and future locational boundaries. This might have forced developers to speculate on how new zones could evolve over time, making it difficult to price investment in long-term projects, increasing the cost of capital and potentially slowing the pace of new generation deployment threatening the government’s Clean Power 2023 ambitions.

2. Complex Consumer Impacts: The possibility of localised power prices raised concerns about the equitable distribution of costs and benefits. Consumer-facing risks include the potential for higher risk premiums on the supply side in certain zones, which could increase electricity bills and create fairness issues, with consumers in different regions facing unequal costs (the so-called “postcode lottery”). Suppliers would need to manage additional risks, likely passing these costs on to end-users.

3. Long Implementation Timelines: The extensive regulatory and legislative adjustments required for zonal pricing pose significant delays, inconsistent with the government’s objective of rapidly advancing the transition away from fossil fuels. The government estimated that implementing zonal pricing would take at least seven years, delaying the benefits of market reform and risking disruption to ongoing investment.

By declining to adopt zonal pricing, DESNZ has stated that it is committed to maintaining a cohesive and fair national market that can more efficiently manage the complexities of system constraints and foster balanced growth in the power sector. The decision also reflects a desire to provide stability and certainty for investors, lower the cost and complexity of investing, and ensure that consumers across Great Britain continue to benefit from uniform wholesale market pricing.

Nevertheless, the issues that REMA set out to address, such as the unstoppable rise in balancing costs, remains.

Proposals for Reformed National Pricing

The government has opted for a unified approach known as “Reformed National Pricing.” In essence, this policy framework retains a single national wholesale market while enhancing how price signals are conveyed to investors and generators and traders. The reforms are designed to provide stronger, more predictable locational investment signals, incentivise efficient siting of new assets, and improve the operational efficiency of the electricity system.

Key elements include:

1. Strategic Spatial Energy Plan (SSEP):
   
   To overcome the mismatch between generation siting and available network transmission capacity, the SSEP will dictate where new assets, such as renewable generation and storage, should be located. This plan will involve mapping out infrastructure demands across electricity, hydrogen, and other energy types. The SSEP, due for its first publication in 2026, will assess infrastructure potential on a regional basis and provide clarity to industry, supporting competition through markets to identify optimal projects. It will be reviewed on a three-year cycle and will also consider the spatial optimisation of flexible demand, such as data centres. The SSEP is alongside the ongoing connection “first ready, first connected” reforms, which require regional strategic alignment.
    
2. Transmission Charging and Connection Fee Reform:
   
   DESNZ has stated that it expects the review to cover Transmission Network Use of System (TNUoS) charges and connection fees. These are designed to provide system users with long-term, predictable cost signals. By “deepening” connection charges on new assets (which would involve the recovery of the total costs that will be incurred as a result of connecting new load or generation to the system, including all costs of network reinforcement, through an up-front connection charge) and updating TNUoS methodologies, the government aims to direct new generation to areas  with adequate or planned transmission capacity, ultimately reducing constraints. The reforms also aim to increase the predictability of TNUoS, update cost drivers to reflect spare network capacity and future network build, and consider the balance between connection charges and ongoing network charges. Ofgem will lead a review of TNUoS, with changes expected to be delivered by 2029 at the latest.
    
3. Operational Efficiency and Balancing Proposals:
   
   In an effort to optimise how the grid is managed in real time and cut costs associated with congestion, the update envisions improvements to balancing and settlement practices. This includes:
   1. Lowering thresholds for participation in the Balancing Mechanism, allowing smaller assets, such as small-scale batteries, to participate in the BM. Currently assets must be 100MW or larger in England and Wales, 30MW or larger in South Scotland and 10MW or larger in North Scotland. Changing this would give NESO more assets to call on when it needs to balance the system, which is particularly important given the increasing proportion of smaller, embedded flexible generation assets on the electricity system.
   2. Aligning market trading deadlines with “gate closure”—the moment when market participants must finalize their plans for how much electricity they will generate or consume in each half-hour period. Previously, these deadlines coincided, but a 2017 rule change allowed trading to continue up to the point when electricity is actually needed, while gate closure remained set an hour earlier. This discrepancy introduces uncertainty for NESO, which requires an accurate, real-time view of the system to maintain grid balance. Bringing these deadlines back into alignment would provide NESO with greater confidence in its operational decisions and ensure that all market participants—regardless of their involvement in the Balancing Mechanism—are subject to the same rules.
   3. Requiring physical notifications to match traded positions.  This would require that the physical plans submitted by electricity generators—referred to as Physical Notifications (PNs)—accurately reflect the trades they have executed in the market. Doing so would provide NESO with a much clearer and more dependable understanding of each asset’s intended generation. With this consistency, NESO can more effectively assess the overall supply and demand balance, enabling it to make more precise and efficient decisions to maintain the stability of the electricity system.
   4. Unit-level bidding: This approach could help create a more level playing field between small and large market participants and enhance the mitigation of market power, especially regarding system constraints. It would also increase transparency in market behaviour. Additional evidence is required to fully assess this option.

These changes will give the National Energy System Operator (NESO) a clearer picture of system needs and more tools to maintain reliable service without inflating network charges. Additional reforms under consideration include shortening the settlement period duration from 30 minutes to 15 or 5 minutes. Industry experts see value in this reduction but crucially ,gate closure (currently 1 hr) would also need to be shortened. DESNZ are also supporting the removal of subsidies from balancing prices to better reflect the true cost of system balancing through code modification P462, for which DESNZ has given its support.

4. Targeted Network Build-Out:

Reformed national pricing is closely aligned with the anticipated Centralised Strategic Network Plan (CSNP), which is expected to lay out the infrastructure blueprint for onshore, offshore, and hydrogen networks over a 25-year horizon. By coupling reformed charges with strategic spatial planning, policymakers hope to promote efficient construction timelines and alleviate the “transitional constraints” stemming from historically underdeveloped transmission corridors. Accelerating grid build-out and optimising the siting of new generation are expected to cut future constraint costs significantly by 2030 compared to previous projections.

5. Constraint Management and Interconnector Flows:

The government, NESO, and Ofgem are also working on measures to reduce the impact of network constraints, including long-term contracts to incentivise new demand behind constraints and technical solutions to increase network capacity. Improving the management of interconnector flows and participating in EU electricity trading platforms are also priorities to support system flexibility and security.

Legal and Practical Implications

From a legal standpoint, the move toward a single national market under reformed pricing will involve new primary legislation, code modifications, and realignment with regulatory licenses. The government plans to introduce legislation to facilitate the necessary changes, including powers for Ofgem and the Secretary of State to amend codes and licenses. The reforms to TNUoS and connection charges are expected to be delivered within this Parliament, and by 2029 at the latest, with a detailed delivery plan to be published later in the year. NESO will also launch consultations on balancing reform and complete its Constraints Collaboration Project, providing further opportunities for stakeholder input.

Key takeaways:

• Stay Engaged with Consultations: Future stakeholder forums and code reviews will offer vital opportunities to shape final network charging reforms. Participation in these processes will help ensure that the reforms deliver fair and efficient outcomes for all market participants.
• Evaluate Project Siting Early: Clear signals from the SSEP will identify optimal locations for generation projects. Early engagement with local authorities, grid planners, and NESO will be crucial for making cost-effective siting decisions and securing timely grid connections.
• Monitor New Legislation: Prepare for updates to primary and secondary legislation, electricity network codes and possible new licensing conditions designed to facilitate the single market structure. Staying informed about legislative developments and regulatory changes will be essential for compliance and strategic planning.
• Assess Investment Strategies: The increased predictability and transparency of locational signals and network charges should be factored into investment appraisals, particularly for new generation and storage projects.

Conclusion

The Summer Update to the Review of Electricity Market Arrangements marks another turning point in the UK’s journey to a low-carbon grid, if not at the same scale should zonal pricing had been introduced.

By rejecting zonal pricing and fostering a Reformed National Pricing model, the government is attempting to offer predictable cost signals, promote robust network expansion, and achieve cost efficiency for consumers.  Industry participants should take active notice of impending legislative changes, public consultations, and novel strategic planning processes such as the SSEP and CSNP. The government’s approach will hopefully provide greater certainty for investors, support the timely delivery of new generation and network infrastructure, and help reduce bills for consumers compared to a scenario without reform.