REMA Update: What does reformed national pricing mean?

Originally launched by the Conservative government in 2022, the Review of Electricity Market Arrangements (REMA) programme has divided opinion amongst players in the power market in Great Britain (GB). In the latest REMA Update published on 10 July 2025 (the Update), the UK government announced its decision to commit to a single national (albeit reformed) wholesale electricity market price, ruling out zonal pricing. The Update was published just days after the opening of Allocation Round 7 for the Contracts for Difference (CfD) scheme, in order to give more certainty to the renewable energy projects seeking to participate in the auction. However, whilst the ruling out of zonal pricing provides clarity on the forward direction, further information is needed on what a reformed national pricing package might entail and what this might mean for projects and their investors. We consider these key questions below.

1. Background

REMA’s core objective was (and is still) widely supported by industry: to reform electricity market arrangements to ensure that they facilitate the goal of decarbonising the GB power system. The programme assessed a range of options for reform across the market including in relation to support for low carbon power and mechanisms to secure the requisite capacity and flexibility.

However no other single issue that REMA has considered has been as divisive as the question of how to reform the wholesale electricity market. Many of the options considered would have significantly changed the shape of the GB market. Some were ruled out prior to the Update including splitting the market, centralised dispatch, new distribution network level markets and nodal pricing. Eventually, the last two options remaining were a move to zonal pricing or reforms alongside a national wholesale price.

As the timeframes for REMA decisions stretched out beyond the originally anticipated horizons, with options for significant structural reforms on the table for almost 3 years, we have seen uncertainty seep into transactions, adding cost and complexity. Therefore, whether it is seen as a positive or negative outcome, the decision to rule out zonal pricing at least provides some investment certainty. But is it sufficient to fully restore investor confidence?

2. What will a reformed national pricing package entail?

In the Update, the government outlined the interventions that might comprise a reformed national pricing package, highlighting that this builds on work already in progress, including that being delivered under the Clean Power 2030 Action Plan.  Officials in the Department for Energy Security and Net Zero (DESNZ) have been clear during REMA stakeholder engagement meetings that continuing with the status quo is not an option, but detailed plans are not expected to be published until the autumn. Ahead of that, we consider what reform options might include.

2.1 The Strategic Spatial Energy Plan and efficient network build-out

As highlighted previously (here), significant changes are underway both to centralise the planning of GB power infrastructure and in relation to management of the GB grid connections queue. In particular, the Update highlights that the Strategic Spatial Energy Plan (SSEP) will be the cornerstone of a reformed national pricing package. This is already under development by the National Energy System Operator (NESO) with the goal of ensuring new generation and storage assets are located in the most efficient places.

The government will also be considering demand. The Update clarifies that the government “will look to ensure strategic investments, such as data centres, will be located in places that deliver the best outcomes for the electricity system”. In this context, DESNZ and the Department for Business and Trade will issue a call for evidence to explore how the Corporate Power Purchase Agreement market can be further developed (although no further timetable is given for doing so).

The SSEP is expected to be implemented via policies such as connections reform, planning reform, seabed leasing, network build-out and network charging to ensure new generation and storage assets are optimally located. Further details on how the SSEP will be implemented will be set out in advance of a public consultation in 2026.

This aligns with other actions that NESO is already taking to optimise development of the UK’s energy systems through the introduction of a tripartite planning system (see box).

Electricity network infrastructure planning will also be more centralised. Although Ofgem, as regulator, will continue to be responsible for approving expenditure for network development under its price controls, the Centralised Strategic Network Plan (CSNP) and the Regional Energy Strategic Plans (RESPs) are expected to reduce grid bottlenecks and constraint costs by providing a longer-term view of system needs and promoting a co-ordinated approach to grid build-out.

As the decarbonisation of the GB energy system deepens, we are increasingly seeing a difference in the value of electrons both temporally and spatially. The SSEP, CSNP and RESPs seek to provide investment signals in a competitive market context to deliver efficient, coordinated social outcomes via private investment. Whilst the need for reform is widely accepted, managing an orderly and equitable transition to the new centralised approach to system planning and grid connections will be a delicate exercise and will inevitably impact valuations of project development portfolios. For those investing in new generation and storage assets, engaging in the development of these plans will be important.

2.2 Changes to transmission and connection charging

To incentivise the optimal location of new projects, the Update also highlights the need for changes to Transmission Network Use of System (TNUoS) charging and to the connection charging regime for both generation and demand. TNUoS will be reformed so that “it reflects the true long-term system benefits of new generation” and this “will ensure that it sends an effective and predictable signal about where new investment should be located within our system, increasing investor certainty and ensuring that the cost of network construction and constraints are factored into the siting decisions made for new generation”. This is likely to mean an increase in TNUoS charges in certain parts of the country, particularly in the north where network upgrades are planned to overcome constraints.

TNUoS reforms highlighted in the Update include:

• A review of TNUoS objectives
• Changes to ensure TNUoS is compatible with the SSEP and the CSNP
• Updates to the cost drivers in the TNUoS methodology (e.g. to reflect the impact of spare network capacity, constraints and future network build)
• Changes to increase the predictability of TNUoS
• Consideration of the balance between connection charges and TNUoS, with a view to “deepening” connection charges (likely to mean an increase for those seeking connection offers)
• Review of charges for storage and demand
• Consideration of the need for any transitional arrangements and of implementation arrangements

TNUoS reforms will be delivered during this Parliament and by 2029 at the very latest. Whilst modifications to TNUoS charging are usually undertaken via an industry code modification process, the government has indicated it is expecting to introduce primary legislation to implement the reforms. Primary legislation may be required to modify the Regulation 838/2010, known as the Limiting Regulation, which still applies in the UK as assimilated EU law and sets limits on the annual average transmission charges payable by generators. It may also have the added benefit for government of reducing the risk of challenge.

As indicated in an open letter from Ofgem in January 2025, industry can expect existing modifications to the Connection and Use of System Code (CUSC) to be reviewed in light of the REMA decision. For example, we are already seeing a move away from CMP444, which sought to introduce a temporary cap and floor to wider TNUoS charges as these had increased significantly due to new network investment, particularly in the north of the country. Ofgem is currently consulting on its minded-to decision to reject CMP444. It is also expected to publish an update on its thinking on enduring changes to the TNUoS methodology shortly, which may include the launch of a Significant Code Review.

Grid connection and TNUoS charges are generally costs for the account of generation projects, either as devex or opex respectively. Increases in these may therefore adversely impact project economics depending on prospective project’s location (which is the intended “pricing signal”). Although the Update is clear that new projects will be impacted (albeit potentially subject to transitional arrangements which are under consideration), it is unclear whether some or all of the changes to TNUoS charges will apply to existing projects.

2.3 Improved balancing and settlement, and constraint management

Reforms will also seek to improve operational efficiency, particularly in relation to network constraints. The government has identified a package of measures as having potential for reform:

• Lower threshold for mandatory participation in the Balancing Mechanism (BM), such that smaller assets, including small-scale batteries, are required to participate
• Re-alignment of the market trading deadline with gate closure to provide more certainty for NESO in executing balancing actions
• Physical Notifications being required to match traded positions to give NESO a more reliable picture of what an asset is expecting to generate
• Unit-level bidding, although further evidence is needed in respect of this option

In addition, consideration is also being given to shortening the imbalance settlement period from 30 minutes to 15 or 5 minutes. Other measures such as dual-imbalance pricing and quasi-pay-as-clear in the BM have been discounted. NESO will consult on these measures later this year and undertake an impact assessment.

In the meantime, the government has made clear that it is also supporting code modification P462. This is expected directly to impact parties to the Balancing and Settlement Code who hold CfDs or are accredited to the Renewable Obligation (RO), but in practice has implications for all BM parties. CfD and RO supported projects currently offer bid prices into the BM to account both for the value of lost generation and lost subsidy. By contrast, unsubsidised generation only needs compensation for lost generation. The result is that, taken in bid price order, the BM may not lead to cost effective actions from a consumer cost perspective. P462 would amend the charging formula in the BM to make a unit whole for any lost support mechanism value.

In addition to BM reforms, work is ongoing in relation to constraint management under the Constraints Collaboration Project, including long-term contracts to incentivise new demand to locate behind constraints (including data centre demand). The government is also looking to improve interconnector flows and hopes that greater co-operation with the EU on energy security and net zero goals outlined in the Common Understanding might include participation in the EU’s electricity trading platforms in all trading timeframes. Finally, the government and NESO are developing measures to maintain grid operability, including a 2030 operability strategy, forecasting future operability needs to provide investment signals for the provision of ancillary services and potentially tracking carbon emissions from ancillary services.

3. Next Steps

Further detail will be needed in order for investors to be in a position fully to assess what a reformed national pricing model means for their existing businesses and any new projects. Full analysis is expected to be published later in the year alongside further details in a Reformed National Pricing Delivery Plan. A range of public bodies will be involved, particularly NESO (to deliver the SSEP, constraint management and BM reform) and Ofgem (in relation to the review of TNUoS and connection charges).

So, whilst the decision to rule-out zonal pricing will bring some clarity on the forward direction, there is still work to be done to provide industry and investors with full visibility of the shape of the GB power market going forwards. These changes will also need to be implemented at a time when the government is estimating that £40 billion of spend is required on average annually to 2030 to deliver the Clean Power 2030 Action Plan outcomes. The government will therefore be keenly focused on managing the process of finalising REMA reforms to encourage this investment.