Clean Power 2030: REMA Update – major market reforms on the horizon

 

The REMA programme commenced in April 2022, considering a wide range of proposals to ensure Great Britain's future decarbonised power system is efficient and cost-effective. A first consultation was published in July 2022, followed by a second consultation in March 2024, which narrowed down the reform options being considered.

The remaining options have been further narrowed in the Autumn Update, with a view to final decisions being made this year based on the assessment criteria of value for money, deliverability, investor confidence, whole-system flexibility and adaptability. Further updates have been provided by the Department for Energy Security & Net Zero (DESNZ) in stakeholder webinars, although we note that these are expressed not to be government policy.

 

Options still being considered

Options discounted in the Autumn Update

Wholesale market reform – both zonal pricing and reformed national pricing are still being considered. The Government has said that "it is clear that 'no change' is not an option, in any scenario". Reforms to balancing arrangements – including shorter settlement periods (e.g. 5 or 15 minutes), a dual imbalance price (with the addition of a less attractive 'reverse' imbalance price), requiring physical notifications to match traded positions, higher imbalance prices during times of scarcity, a lower threshold for mandatory Balancing Mechanism participation (e.g. 1-10 MW), a quasi pay-as-clear balancing mechanism and realignment of gate closure and the market trading deadline. Non-firm access rights for new storage assets. Improving NESO's existing tools to manage interconnector flows – including improvements to System Operator to System Operator trading and interconnector participation in new constraint management markets. Expanded constraint management and operability measures – these are being considered as part of the CP30 Plan. CfD reforms – including a capacity-based CfD, deemed CfD, reference price reforms, a partial CfD and retention of the existing CfD form with minimal changes. There will be no substantial reform to CfD design until Allocation Round (AR) 9 at the earliest (expected to be in 2027). Optimised Capacity Market - with minimum procurement targets for flexible low carbon technologies.

Non-firm network access rights for generation. Centralised dispatch – the Government is not minded to take this forward under either the reformed national pricing or zonal pricing models. The existing self-dispatch model is assumed to be retained. Longer gate closure.

 

Wholesale market reform

The Government is continuing to explore how zonal pricing and reformed national pricing could improve locational operational signals, locational investment signals and optimise dispatch.

Its initial analysis is that zonal pricing is the only option which could significantly improve locational operational signals but it also acknowledges the major change that a move to zonal pricing would mean for investors, the likely increased cost of capital for generators and the need for clarity as soon as possible.

Zonal pricing

Many of the key design choices for a zonal pricing model are still under consideration, including the number and location of zones and the appropriate locational risk allocation for both generators and consumers.

Boundaries - DESNZ is seeking to strike a balance between reducing constraints and maintaining sufficient liquidity within zones. 12 zones are being modelled for the purpose of making a decision as to whether to adopt zonal pricing but the final design would be determined using a methodology based on independent assessment of network congestion. The number and location of zones is expected to be updated periodically. NESO has, separately, said that if zonal pricing is adopted, it would encourage alignment between the market zones and the economic zones used to model the Strategic Spatial Energy Plan (SSEP) to ensure complementary locational signals are sent.

Trading - Under a zonal pricing model, generators would self-dispatch and have firm access rights only in their zone, with NESO allocating transmission capacity between zones and managing balancing and trading. DESNZ's expectation is that interzonal capacity would first be allocated at day-ahead stage using one single clear auction in which the available cross-zonal capacity determines zonal prices and generators clear at the marginal price in their zone. Physical bilateral trading would still be possible within zones but it is expected that most trading would move to auctions. Intra-day trading could take the form of auctions (in which any capacity left after the day-ahead auction would be auctioned), a continuous pay-as-bid market or a combination of both.

Balancing - The Nordic Balancing Model, which is a zonal self-dispatch model, is being used as a key reference for GB's zonal balancing arrangements. DESNZ is considering a range of approaches to zonal balancing, including independent balancing of each zone, allocating some cross-zonal capacity for balancing so that some imbalances can be addressed through other zones or a combined approach.

The Government is undertaking further analysis on the scale and duration of the cost of capital impacts of zonal pricing and is developing a full cost-benefit analysis of a move to zonal pricing, as well as continuing to assess additional mitigations for generators such as protections for existing CfD assets, the introduction of virtual trading hubs to improve liquidity and hedging mechanisms such as Financial Transmission Rights to mitigate price risk.

Reformed national pricing

The Government's chosen national pricing model would largely be implemented through TNUoS and connection charge reform (it is considering reforming the locational charge methodology to better reflect existing unconstrained network capacity, linking charges to planned network build and deepening connection charges). Such an approach would move away from the temporary cap and floor proposed to apply to wider TNUoS generation charges from 1 April 2026. A national pricing model would likely result in higher TNUoS charges in some areas compared to the current level and higher TNUoS charges than under a zonal pricing model.

Network charging reforms could be implemented alongside reforms to balancing arrangements, non-firm access rights for new storage assets and changes to interconnector operation (to the extent possible within existing international agreements). As a reformed national pricing model would provide weaker locational signals than a zonal pricing model, the Government also expects further actions outside of the REMA programme may be needed including an even greater role for strategic plans, such as the SSEP, and connections reform.

Legacy and transitional arrangements

The Government has reiterated its commitment to a smooth transition to the reformed arrangements, which minimises uncertainty for investors and ensures that any interventions to protect investors in existing and transitional assets are aligned with the broader market reforms.

CfDs

Projects awarded CfDs in AR7 will be treated the same as those with existing CfDs in relation to legacy and transitional arrangements. DESNZ has indicated that it would be beneficial for any CfD protections to apply for the entire CfD contract length due to CfD-related revenue expectations for the length of the CfD term but that other schemes may receive less protection.

If zonal pricing is introduced, the Government expects that existing and AR7 CfD-holders will be insulated from zonal price risk by the existing mechanism to update the CfD reference price to the relevant zonal reference price. In respect of locational volume risk, DESNZ is considering providing some protection to all legacy generation assets (see below).

It seems likely, however, that the detailed design of any zonal or reformed national pricing model and the protections available for CfD-holders will not be available before the AR7 application window, which may result in higher bid prices in AR7 to reflect the uncertainty around the detailed policy design. In a worst case scenario, lack of clarity about zonal pricing could jeopardise a successful AR7 outcome, which is necessary for the Government's clean power 2030 target.

Bidders in future CfD rounds should expect less protection. DESNZ considers that, beyond AR7, developers should be able to take zonal pricing or increased TNUoS payments under a reformed national pricing model into account in their bidding strategy.

Other legacy protection

DESNZ is considering a bespoke financial protection scheme for legacy and transitional assets in respect of locational volume risk, which would be available to eligible generators and paid for through a levy on suppliers. Such a scheme could involve payments to generators based on a volume risk calculation (e.g. using historical Balancing Mechanism volume turn-downs or an estimate of economic curtailment).

For assets other than legacy and transitional CfD assets, DESNZ has indicated that the arguments for price protection are less compelling.

Other potential interventions, including their duration, are still under consideration (e.g. grace periods during which certain assets that have reached an investment maturity threshold but have not yet achieved COD are protected from zonal or reformed national pricing changes or a longer implementation period following the final REMA decisions).

Consumer price redistribution

The Government is considering a form of price redistribution if zonal pricing is introduced but does not result in an equitable distribution of benefits for consumers across zones.

For domestic consumers, the Government's initial view is that retail reconciliation, which protects consumers from locational investment signals but not locational operational signals, is the best approach. This would mean that wholesale locational prices on consumer bills would be more consistent across zones but consumers would still be incentivised to flex their demand to take advantage of times when power prices are low locally.

For energy intensive industries, the Government is considering providing support to those disproportionately impacted by zonal pricing. Options under consideration include increasing the level of subsidy provided through the British Industry Supercharger (by increasing the percentage of network costs which are supported), awarding free Financial Transmission Rights and subsidising the difference between wholesale costs paid under the current national system and the price paid under any new zonal pricing system.

 

Key considerations for investors: Final REMA decisions need to be taken in a timely manner this year to end the long-running uncertainty surrounding the direction of the REMA programme and unlock the investment the Government has called for in its CP30 Plan. The detail of how the remaining options fit together, and the consequent allocation of risks and incentives across the whole system for both new and existing projects, will be key to ensuring investor confidence. Whatever final decisions are taken, it is clear that the reforms are likely to have a material impact on how current operators and future developers of GB generation assets, as well as power consumers, consider their investments and market interaction. This includes: investors in both existing and new generation assets and assets with high electricity demand, who will need to reconsider their changed price and volume risk profile based on the final wholesale market design; projects coming forward for CfDs from AR9 onwards, for whom the economics of the CfD may be significantly different; investors in BESS assets, and investors in other dispatchable plant, given the proposed changes to the Capacity Market and the length of settlement periods and the potential introduction of non-firm transmission rights for storage; and the introduction of many of these measures would require review of the terms of PPAs and optimisation agreements, and the terms of change in law clauses should be considered in new contracts being put in place as REMA continues its development.

Next steps

The Government aims to conclude the policy development phase of the REMA programme by mid-2025, with the final REMA decisions to be announced before the opening of the AR7 auction later this year, and implementation to start from late 2025 onwards. Further work on the detailed design, including a consultation on implementation, is expected to follow the Government's decision.

Whilst the Autumn Update is not a consultation, the Government states that it is keen to engage with stakeholders on the practicalities of how either zonal pricing or reformed national pricing could be made to work best. Feedback and queries can be submitted to REMAMailbox@energysecurity.gov.uk.

If you would like to understand more about what REMA means for you or your business, please do not hesitate to get in touch.

Key REMA terms: Zonal pricing – the GB electricity network would be divided into clearly defined zones, each with a single electricity price. The price of electricity flowing between zones would vary depending on network congestion and the supply and demand balance in each zone. Reformed national pricing – a single national electricity price would be retained with the main reforms under consideration being to transmission network charging and balancing arrangements. Locational investment signals – market signals which incentivise investment in new assets in locations which maximise overall system benefit. Locational operational signals – market signals which incentivise generation output and demand at times and in locations which maximise overall system benefit. Non-firm network access rights – rights to access the transmission network which are not financially guaranteed. Where there are constrains on the grid in the relevant area, users with non-firm rights are constrained ahead of firm rights holders and are not entitled to compensation for such constraint. Capacity-based CfD – generators receive a fixed £/MWh payment regardless of actual generation. Deemed CfD – generators receive a difference payment calculated using deemed output based on an asset's generation potential rather than metered output. Centralised dispatch – participants would notify NESO of their availability ahead of time and NESO would schedule generation and dispatch based on system-wide costs, constraints and objectives.