The Department for Energy Security & Net Zero responds to the second REMA Consultation

1. REMA Autumn Update

Amongst the flurry of other policy announcements and consultations, DESNZ published their autumn update on the Review of Electricity Market Arrangements (REMA) in December 2024 (“Autumn Update”) together with a summary of consultation responses to the previous REMA consultation. The Autumn Update provides an update on feedback gathered from the second REMA Consultation of March 2024, and ongoing dialogue with stakeholders. This update is crucial for stakeholders as it outlines potential changes to wholesale market pricing and the Contracts for Difference (CfD) scheme, which are pivotal for future investments in renewable energy and low-carbon technologies and enabling GB to achieve Clean Power by 2030.

2. Summary

Background

The REMA Programme was first announced in April 2022, with the aim of transforming the electricity market to support a renewables-dominated system. It focusses on longer term reforms to the electricity market, complimenting shorter and medium term reform such as the Clean Power 2030 Action Plan (see our January 2025 update for details). The initial consultation was essentially the problem statement, with a large number of options on a number of aspects of the electricity market presented for consideration. The second consultation, published in March 2024, identified key challenges and proposed options for market reform. The Autumn Update narrows down these options and provides some element of further clarity for investors and stakeholders. See our April 2023 update for further details.

The Autumn Update considers:

1. Wholesale Electricity Market Reform
2. Legacy and Transitional Arrangements as REMA is implemented
3. Reforming the Contracts for Difference (CfD) Scheme (the current primary government driven financial support mechanism for renewable/low carbon generation projects)
4. Transitioning from Unabated Gas to Low-Carbon solutions to our need for some level of flexible generation.

Summary of key decisions

Stressed throughout the Autumn Update is that a priority for DESNZ is to minimise transitional uncertainty for investors whilst still implementing reform for the benefit of consumers. This key risk to a transformed power system, both physically and structurally, is an important one to focus on given the amount of capital required to meet CP2030 and beyond.

3. The Autumn Update

Wholesale Market Reform

The Autumn Update considers two main options for wholesale market reform: zonal pricing and reformed national pricing.  Both options remain under equal consideration, with no final decision made yet but DESNZ have set out that ‘no change’ is off the cards, and as such wholesale pricing reform is coming to the GB wholesale electricity market.

Zonal pricing could provide more accurate locational signals for where to locate generation and/or when to dispatch generation, potentially reducing system costs and consumer bills.  However, it may also increase risks for generators, affecting the cost of capital, as well as undermine investment certainty for those projects beyond AR7.  Reformed national pricing, on the other hand, would involve strengthening network charging and balancing incentives but may not address locational operational signals as effectively.

Zonal pricing: This proposed approach involves dividing the electricity market into different zones, each with its own wholesale price for electricity based on local supply and demand conditions.  The aim is to provide more accurate locational signals, which could incentivise more efficient investment and operational decisions for generation.  By reflecting the true cost of delivering electricity to different parts of the network, the suggestion zonal pricing could help reduce overall system costs and lower consumer bills. The Autumn Update does not confirm whether savings achieved through zonal pricing would be equally distributed across consumers or whether consumption located in zones where wholesale prices were cheaper/higher might see this impacting their end user electricity costs. Clearly this is a sensitive point for investment decisions on where to locate large scale demand projects – such as gigafactories and hyperscale data centres where there is international competition to attract investment – and the Autumn Update recognises this.

Under zonal pricing, the market would be designed to ensure that generators only have firm access rights within their specific zone.  This means that when selling power, generators would receive the prevailing price in their zone, which could vary significantly from prices in other zones.  A Market Operator would be responsible for allocating transmission capacity for the flow of electricity between zones, with capacity allocation being implicit in the day-ahead and intraday markets.  This would involve Power Exchanges and the National Electricity System Operator (NESO) working together to calculate and allocate network capacity.

However, zonal pricing also presents challenges. It would transfer some locational risk to generators, potentially increasing the cost of capital for new projects.  This could affect investment decisions and the overall pace of renewable energy deployment.  The Government is considering various mitigations to help generators manage these risks, such as financial transmission rights (FTRs) and adjustments to the CfD scheme.  Additionally, the implementation of zonal pricing would represent a major change to the current market arrangements, requiring careful planning and a clear methodology for setting zonal boundaries.

To mitigate these challenges, DESNZ recognises that early clarity and appropriate transitional and legacy arrangements for investors would be needed to counter any increase to the cost of capital. Such a change to the cost of capital, and the scale and duration of the change would impact any cost benefit analysis and would need to be factored into any decision. Whilst this is recognised, the Autumn Update also notes that exact details of the design areas of zonal pricing would be decided during potential implementation of the reform. It is not clear how the true cost and any benefits will be known earlier.

As noted above, the commitment from Government is to treat CfDs allocated in AR7 and those that already exist in the same way. The expectation to insulated projects from this is that the strike prices would remain the same and the reference price in the CfD would be updated to the zonal price, thereby removing the increased locational price risk from these projects.

Reformed national pricing:

Reformed national pricing is the alternative option being considered for wholesale market reform.  This approach would retain a single national price for electricity, but would involve significant reforms to network charging and balancing incentives to improve locational investment signals.  The aim is to send stronger and more predictable signals to generators about where to locate new capacity, thereby reducing network constraints and improving overall system efficiency.

One of the key components of reformed national pricing is the reform of Transmission Network Use of System (TNUoS) charges.  The current TNUoS methodology is seen as unpredictable and not fully reflective of the actual costs of network constraints.  Proposed reforms include improving the accuracy and predictability of TNUoS charges by better reflecting where there is existing unconstrained or spare capacity on the network.  This would incentivise generators to locate in areas with available capacity, reducing the need for costly network reinforcements.

Another aspect of reformed national pricing is the introduction of incremental reforms to the NESO's balancing arrangements.  These reforms aim to make it easier for the NESO to balance the system by incentivising market participants to 'self-balance' and minimise differences between contracted and metered positions.  Options being considered include returning to a dual imbalance price, lowering the threshold for mandatory participation in the Balancing Mechanism, and reducing the settlement period duration.

While reformed national pricing would be less complex to implement than zonal pricing and would likely cause less disruption for investors, the Autumn Update considers that it may not address locational operational signals as effectively.  This could result in ongoing inefficiencies and higher costs for managing redispatch and network constraints.  The Government is also considering additional non-market measures, such as centralised system and generation planning, as set out in the Strategic Spatial Energy Plan, to complement the reformed national pricing approach and ensure that new generation is located in the most beneficial areas.

Legacy and Transitional Arrangements

The Government is committed to treating agreements awarded under the next CfD allocation round (AR7) in the same way as existing CfD agreements.  This includes insulating these contracts from zonal price risk if zonal pricing is adopted.  The Autumn Update also outlines potential mitigations to reduce risks for current market participants and near-term investors, underlining that DESNZ is very keen to minimise uncertainty or investment hiatus that any reform to the market arrangements may cause.

A detailed scheme-by-scheme analysis is being conducted to assess the functional effects and financial impacts of REMA reforms on existing arrangements.  This analysis covers a range of government support schemes, including:

• Contracts for Difference (CfD)
• The Capacity Market (CM)
• The Renewables Obligation (RO)
• Feed-in-Tariffs (FiTs)
• The Net Zero Hydrogen Fund
• Interconnector cap and floor arrangements
• Nuclear CfD and Regulated Asset Base (RAB) mechanisms

Additionally, schemes currently in development, such as offshore hybrid assets, hydrogen business models, Power BECCS, Power CCUS Dispatchable Power Agreement (DPA), Long Duration Electricity Storage (LDES), and the potential Hydrogen to Power business model, are also being considered.

The Government has been looking at the legacy arrangements in two ways when considering reform: the functional effects, and the financial impacts.

Functional effects refer to the impact of market changes on the efficiency and operation of existing contracts and schemes.  For example, the introduction of zonal pricing would affect the drivers of wholesale prices, potentially requiring changes to CfD contracts to ensure they remain functional.  hence the amendment of existing and AR7 CfDs to use a local zonal reference price, maintaining the integrity of the strike prices and insulating these contracts from zonal price risk.

Financial impacts involve changes to asset revenue, price, volume, and risk levels due to new market arrangements.  The Government is considering various interventions to manage these impacts and ensure a smooth transition.  Potential options include:

• Reformed CfD: Offering a reformed CfD to existing holders for the remainder of their current contracts to help manage risks.
• Financial Transmission Rights (FTRs): Developing an FTR market to support zonal pricing, allowing market participants to hedge against cross-zonal price risks.  The Government is considering whether to offer a free allocation of FTRs to legacy and AR7 assets.
• Further Mitigations: Exploring additional mitigations to help existing investments manage other risks, such as volume risk, on a fair and robust basis.

Reforming the CfD Scheme

The CfD scheme has been pivotal in driving renewable energy investment in the UK.  However, as the electricity system evolves, the scheme faces new challenges that necessitate reform, which are as follows:

1. Investment Growth: Increasing periods of generation surplus due to higher renewable penetration introduce price and volume risks, particularly under the negative pricing rule for AR4 contracts and beyond. This uncertainty can raise the cost of capital and strike prices, impacting consumer bills.
2. System Efficiency: The current CfD structure shields generators from price risks, reducing incentives for system-efficient design and location.  Strengthening locational signals through zonal or reformed national pricing could encourage more efficient siting of projects.
3. Optimal Operation: Linking subsidy payments to metered output incentivises generators to maximise output regardless of system need, leading to inefficiencies and higher system costs.  Addressing these operational distortions is crucial as CfD-supported generation grows.

The CfD reform options set out in the Autumn Update are:

1. Capacity-Based CfDs: Payments based on capacity rather than output to encourage efficient operation.
2. Deemed CfDs: Payments based on a deemed level of output to manage risks associated with generation surplus.
3. Reference Price Reform: Adjusting the reference price to better reflect the value of generation at different times and locations.
4. Partial CfDs: Combining fixed and variable payments to balance market signals and revenue certainty.

Significant changes to the CfD scheme will not be implemented until AR9 at the earliest, allowing the industry to adjust and ensuring the delivery of CP2030  targets.  The Government is engaging with stakeholders to explore these options and assess their potential benefits. It is unclear from the Autumn Update how AR8 CfD projects will be treated.

Transitioning to Low Carbon Flexibility

It has been accepted that gas generation will continue to play an important role in the clean power transition, but will have a reserve role. DESNZ wants to ensure that sufficient capacity is retained as generation hours reduce, and that existing and future assets will be decarbonised. Whilst this may be achieved through the design of the CM, the Government is also considering novel out-of-the-market mechanisms to manage the reserve once the volume has reduced, and long-duration low-carbon flexible technologies have been deployed.

Short-duration flexibility technologies, such as batteries and consumer-led flexibility (e.g., demand-side response), are well-suited to managing daily peaks and troughs in electricity demand, whereas long-duration flexibility technologies are required to manage longer periods (days or even weeks) of low renewable output, which short-duration technologies cannot cover.  Currently, unabated gas generation fulfils this role, but the goal is to transition to low-carbon alternatives such as:

• Power CCUS (Carbon Capture, Usage, and Storage): Gas plants equipped with carbon capture technology to reduce emissions.
• Hydrogen to Power (H2P): Using hydrogen as a fuel for power generation.
• Long Duration Electricity Storage (LDES): Technologies like pumped hydro storage that can store large amounts of energy for extended periods.

The CM remains the primary mechanism for ensuring security of electricity supply in Great Britain.  The CM has successfully secured the necessary capacity in recent auctions and will continue to play a key role in the transition to low-carbon flexibility.  Proposed reforms to the CM aim to:

• Support the Decarbonisation of Existing Gas Plants: Introducing decarbonisation readiness requirements to ensure that investments in new or significantly refurbished gas plants have a credible path to transition to low-carbon technologies like hydrogen or CCUS.
• Enable Low-Carbon Flexible Technologies: Optimising the design of the CM auction to allow low-carbon flexible technologies to access different clearing prices by introducing minimum procurement targets (minima).  This approach, known as the Optimised CM, would support the deployment of a competitive mix of low-carbon flexible capacity.

Alongside this, the Government is examining the challenges associated with accelerating the use and deployment of short-duration flexible technologies. Key areas of focus include:

• Inefficient Market Operations: Identifying and addressing inefficiencies in market operations that hinder the participation of short-duration flexible technologies.
• Barriers to Market Access: Removing obstacles that prevent these technologies from fully participating in electricity markets.
• Temporal Signals: Ensuring that market signals reflect system needs more accurately, encouraging the efficient use of flexible capacity.
• Locational Signals: Improving locational signals to reflect the true value of flexibility in different parts of the network.

To support the transition, the Government, alongside Ofgem and NESO, will publish a Low-Carbon Flexibility Roadmap in 2025.  This roadmap will outline actions for the Government, regulators, and industry to:

• Support the Delivery of 2030 Clean Power and 2050 Net Zero Targets: Providing a coherent and comprehensive vision for achieving the required levels of flexibility.
• Enable Investment: Offering clarity and reassurance on the Government's commitment to facilitating flexibility capacity growth.
• Remove Blockers and Promote Coordination: Addressing barriers to investment and promoting coordination across government and industry.

Conclusion and comment

The Autumn Update provides a useful indication of the direction of travel for GB electricity market developers, investors and stakeholders, as well providing the clear signal that the Government wishes to maintain the pace of investment during the policy development and implementation of the final package of reforms. Nevertheless, much uncertainty remains, particularly in terms of whether zonal pricing will be implemented.

The Government has stated its ambition to complete the policy development phase of the REMA programme by around mid-2025, with the timetable for implementation being subject to the policies selected during this stage.

Stakeholders are encouraged to continue to provide feedback to DESNZ on REMA and the Autumn Update in particular, in order to ensure that all views are taken into account in the policy developments over the coming months.