REMA: what lies ahead

Background

REMA is a comprehensive initiative by the government aimed at reforming the electricity market to support the transition to a decarbonized, cost-effective and secure electricity system by 2035.

Launched by the government in July 2022, the first REMA consultation set out the case for change and the potential options for reforming the electricity market across various areas. The initial options ranged from evolution to revolution. Following public responses, the reform options were narrowed in the second REMA consultation published in March 2024 and further distilled in the Autumn update in December 2024, published alongside the Clean Power 2030 Action Plan (CP30 Action Plan) – the government’s roadmap to achieving a clean, sustainable and resilient power system by 2030. For more information on the CP30 Action Plan, see our briefing: Clean Power 2030: The UK's path to a sustainable energy future.

Recap of REMA proposals

Wholesale market reform

To ensure the UK’s electricity market is fit for a decarbonised future, REMA proposes moving from a single national electricity price to locational pricing, however, a decision is yet to be taken between zonal pricing and reformed national pricing. The key features of each option are as follows:

• Zonal pricing: This would require splitting the network into separate clearly defined zones, based on network congestions, with each zone having its own wholesale price dictated by within-zone supply and demand. Generators would have firm access rights within their zone, but any cross-zonal trading would require securing transmission capacity from the market operator, although this would be implicit in the day-ahead and intraday markets.

• Reformed national pricing: As the name suggests, this would see the current single national price retained but with the reform of TNUoS charges (with DNUoS charges to follow suit) and incremental changes to the balancing arrangements. In terms of network charging, Ofgem is looking to incentivise generators to locate in areas of available network capacity through a combination of changes to the locational charge methodology used in the TNUoS charges calculation (so that generators in areas of limited capacity are subject to a higher network charge reflective of their effect on the network) and changes to the allocation of reinforcement costs (so that some or all such costs are borne by the generator who triggered them instead of being entirely socialised amongst network users through TNUoS charges). Also, to improve predictability of charges, Ofgem is considering introducing a more forward-looking network design to calculate charges. With respect to balancing, the government is looking to improve balancing incentives. The options considered to achieve this include (amongst others): returning to a dual imbalance price; lowering the threshold for mandatory participation in the Balancing Mechanism; reducing the settlement period duration; realigning gate closure with the deadline for market trading.

Each of the above options has their pros and cons. Zonal pricing should give better locational investment and operational signals to investors and demand customers, thereby contributing to regional growth and a reduction in system costs and consumer bills. The downside is that it would require a market overhaul, could affect market liquidity and would expose market participants to cross-zonal pricing risk, which would need to be managed through appropriate hedging products. It also has the potential to increase capital costs, the extent of which remains unclear. In contrast to zonal pricing, a reformed national pricing model would be less disruptive for investors and their cost of capital and should also send a stronger locational investment signal. However, there would be very limited improvement of locational operational signals, resulting in many of the existing market issues remaining unresolved albeit manageable at a higher cost. Also, compared to zonal pricing, it may require more strengthening of planning and connections regimes and a larger electricity system (in terms of generation and network build). The government is therefore continuing to assess the risks and cost-benefits of both options, with no firm decision having yet been made.

Whichever approach is adopted, the government has, for the time being, discounted taking forwards centralised dispatch, under which participants would notify the Electricity System Operator (ESO) of their availability ahead of time and ESO would schedule and dispatch generation based on system-wide costs, constraints, and objectives. Also, certain other market changes could be implemented regardless of the option chosen, such as: shortening the settlement period duration (e.g. to 5 or 15 minutes); expanding constraint management measures to reduce the cost of constraints; and addressing wider operability measures.

The choice between zonal pricing and reformed national pricing is of course only part of the jigsaw. In either case, the devil will be in the detail, which is also yet to be confirmed (and unlikely to be known until implementation). Zonal pricing will require the definition of zonal boundaries, which the government is currently unable to confirm. TNUoS charges will need to be revisited so they adapt to a zonal market. The trading and balancing arrangements will need to be determined. For example, to address cross-zonal pricing risk, hedging products will need to be developed that will offset the price differential between two zones. One of the potential products considered are Financial Transmission Rights (FTRs) giving the holder the right to receive (‘FTR option’) or the obligation to pay (‘FTR obligation’) the price differential between the zones in which the electricity was sold and purchased. If introduced, legacy and assets awarded support under the contract for difference (CfD) allocation round (AR) 7 could potentially receive free allocation of FTRs, but there are concerns about the suitability of this product for intermittent generation projects. Liquidity risk will need to be addressed, for which purpose the government is considering potentially introducing virtual trading hubs, where the hub price would be determined based on an average or index of prices of the areas captured within the hub, but there are different ways that a hub price can be calculated.

Capacity market reform

Whilst bespoke support mechanisms may be necessary for the deployment of low-carbon flexible technologies, the government is also continuing to consider how the capacity market (CM) can be changed to provide a support route as technologies and enabling infrastructure develop. One of the options is to optimise the design of the CM auction by introducing a minimum procurement target (or ‘minima’), although this would require a sufficient pipeline of projects to support competitive tension. To ensure security of supply, the government is also exploring the changing nature of future stress events and assessing the case for reforming aspects of the reliability framework.

Impact on market players

In one way or another, everyone will be impacted by REMA reforms, from household and business consumers to electricity suppliers, traders, and investors and lenders to existing and new power projects, with zonal pricing having the biggest impact. The exact impact will, however, depend on location, flexibility to respond to the adopted market changes, and any customer shielding and transitional and grandfathering arrangements introduced as part of REMA reforms.

A move to zonal pricing would be a significant change of the wholesale electricity market that would trigger the need to revisit the pricing provisions under commodity transactions and government support agreements linked to the wholesale electricity price. By way of example:

• The CfD scheme specifically recognises the splitting of the GB electricity market as a trigger for reviewing the market reference price and requires that the market reference price calculation pays regard to the physical location of the project and network constraints. Moreover, the government has confirmed that the market reference price under the CfDs would be updated to a zonal reference price whilst leaving the strike price unaffected. This is to ensure that CfD projects are insulated from zonal price risk, but it would not insulate them from the increased risk of negative market prices, which some projects will be more exposed to than others and which risk is not protected under all CfDs. (Projects holding a CfD from AR4 and onwards do not receive their CfD support payment during periods of negative day-ahead market prices.)

• Whilst some power purchase agreements (PPAs), whether physical or virtual, will have provisions specifically prescribed to deal with this eventuality, most will not and instead have general change in law provisions designed to “preserve the balance of risks and rewards” between the parties. Given that PPAs would usually be linked to a specific project, the parties are likely to agree to replace the wholesale electricity price with the price for the zone where the project is located. Whether this would achieve the same economic benefit for the offtaker if its demand or customer demand is located in a different zone is yet to be seen. Furthermore, corporate offtakers that have entered virtual PPAs may find themselves exposed to basis risk due to the mismatch between the market reference price used under their virtual PPAs and the market price at which they purchase electricity under their supply agreements.

• The matter may be even more complex in the case of commodity derivatives, which will often not be linked to a specific project or, therefore, specific location. Instead, the parties will be relying on any market disruption fallback provisions that may have been agreed, and which may ultimately lead to termination of the affected transaction and crystallisation of a termination payment.

Those entering into new agreements over the coming months may wish to consider pre-determining the implications of transitioning to zonal pricing to mitigate future uncertainties.

A zonal market would also shift some locational risk to generators by exposing them to locational price risk (as zonal prices may be lower or higher and more volatile compared to the national price) and/or volume risk (as generators may be unable to dispatch during periods of network constraint and their curtailment compensation may be adversely affected). Locational risk will particularly be relevant to projects located in areas with increased periods of over-supply, who may see increased exposure to negative market prices, adversely impacting their project economics. New projects may be able to mitigate this risk through developing the right type of project in the right location, optimising project design, or pricing this risk in their CfD strike price or PPA electricity price (as applicable), whereas existing projects will need to carefully consider their zonal price when making optimisation, trading and dispatch decisions, which may be easier for some projects than others. Recognising locational risk exposure, the government is considering if any mitigation could be introduced to help manage it while still delivering value for consumers. In the case of CfD projects, this could potentially include reforming the CfD scheme both for existing and new CfD holders (e.g. by introducing subsidy payments based on ‘deemed output’). However, projects accredited under the Renewables Obligation (RO) scheme may also need protection as they would equally be losing their subsidy when unable to dispatch. If introduced, FTRs may have a role to play in mitigating locational risk but they would need to consider any lost government subsidy. The government’s decision on grandfathering will clearly be important for those already invested, however, one person’s grandfathered right is another person’s competitive distortion.

Consumers may see changes in their electricity costs: those in areas with surplus generation could see a reduction of their electricity bills, whereas those in areas where demand exceeds supply may need to change their consumption patterns to reduce their energy costs. This could be a challenge for certain Energy Intensive Industries (EIIs) that are less flexible in their production process and therefore unable to take advantage of locational price signals. Some EIIs may also see changes in the compensation they receive for certain energy related costs, negatively impacting their global competitiveness.

The government is considering consumer protections carefully, such as equalising or reducing price differences across zones while maintaining location-specific time incentives. Additionally, new EIIs like data centres could be encouraged to locate in areas with lower electricity prices, boosting regional growth. However, there is evidence that data centre developers are increasingly exploring gas network connections for onsite combined heat and power plants to meet energy demands.

Whatever route is taken, sharpening of locational signals should have a positive effect on the deployment of low-carbon flexible technologies and remove some of the market barriers they currently face.

What’s next?

The government’s policy decisions on REMA are expected within the coming months, ahead of the CfD AR7 which is due to open in ‘summer 2025’.

In its Open Letter from January this year, Ofgem said that it would share its thoughts on the general direction of travel with regards to network charging shortly after the REMA decision. Amongst other options, this may include a consultation on launching a Significant Code Review, if considered necessary. Changes to the DUoS charging regime should follow, dictated by the approach taken on TNUoS charges through REMA.

The government is also focused on delivering the CfD reforms necessary to achieve its CP2030 Action Plan, although any significant changes to the CfD which may be introduced as part of REMA are not expected to be implemented until AR9 at the earliest. Additionally, pre-operational projects that have achieved a certain level of development by a specified deadline may be granted a grace period, although this is still under consideration.

To ensure security of supply, a Low Carbon Flexibility Roadmap will be published later in 2025. It aims to promote the development of low-carbon flexible technologies through market reforms, providing batteries and consumer-led flexibility with fair market access and better market utilisation. For its part, ESO has said that it will identify and deliver on opportunities to enhance flexibility within the current market arrangements, aligning with REMA outcomes.

In parallel with REMA, the government is evaluating the need for government intervention in corporate PPAs and undertaking a broad review of the Renewable Energy Guarantees of Origin (REGO) scheme with the view to further driving system decarbonisation.

There is a strong divide amongst stakeholders on the way forward. Whilst there are those that support the move to zonal pricing, others are very much opposed to it, which could ultimately undermine the government’s efforts to achieve its CP30 Action Plan. The pressure is on.