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With electricity demand set to at least double over the next 13 years, REMA will focus on establishing a fit-for-purpose market design, identifying and implementing the reforms needed to GB electricity markets that work for businesses, industry, and households.

REMA will consider a range of options for reform to electricity markets and policies that can provide signals for the investment in, and operation of, assets that generate or use electricity. It will cover wholesale markets, the balancing mechanism, and ancillary services provision; as well as all policies with an impact on these, including the Capacity Market and Contracts for Difference.

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In terms of scope, REMA encompasses non-retail aspects of electricity markets, focusing on facilitating the balancing of supply and demand of electricity, and the policies that are meant to incentivise investments in the assets that generate or use electricity. More specifically, the scope of REMA includes the balancing mechanism, ancillary services, the current Contracts for Difference (CfD) scheme, and the Capacity Market (CM).

If you would like any further information, or to discuss any legal issues relating to the review of electricity markets (REMA) and potential reform, please contact Ben Sheppard or any member of the Infrastructure & Energy team.

Such a stark conclusion was to be expected. The current market arrangements were designed in the 1980s to facilitate liberalisation of the electricity market. The design resulted in the Electricity Act 1989, the framework for privatisation of the electricity industry in the 1990s. This is the framework (albeit with piecemeal amendments over the decades) that still governs the electricity industry today even though it is vastly different from the pre-privatisation landscape.

In the summer of 2022, and in response to the recent energy crisis, BEIS announced its intention to redesign the current UK electricity market to enable it to better accommodate future challenges presented by the transition to a distributed renewable energy system.

BEIS expects to publish a second consultation by the end of 2023, and this one is intended to provide an opportunity for stakeholders to provide further input and feedback on the proposed reforms to the electricity market. The government has indicated that they may still make decisions on shorter-term reforms if they are required to protect consumers. However, it seems unlikely BEIS will need to make any rash decisions given current market prices.

The Department of Energy Security and Net Zero (DESNZ) yesterday (8 March) released the conclusion of its review of electricity market arrangements (REMA) consultation, confirming that 80% of respondents felt current markets are not fit for purpose.

Running from 18 July to 10 October 2022, the consultation was published online and invited views on the vision and objectives for future electricity markets proposed by the government as well as welcoming insights on how best to approach a reform.

Such fundamental reform is under consideration because there is a growing mismatch between how the UK electricity markets are structured and how renewable and other low carbon technologies operate. An example is the determination of electricity pricing.

Currently the wholesale electricity price is determined by the cost of the most expensive unit of generation procured. As gas power plants are usually the most expensive generators, this effectively means that the price of gas generation sets the market price for all generators, including those who have much lower cost bases, such as offshore windfarms.

The Government is seeking to address this imbalance currently with the electricity generator levy (see our article here for more information) but structural reform is needed to decouple gas and electricity prices given the longer-term outlook and aims to decarbonise the electricity market.

The response confirms that Government will not take forward a pay-as-bid pricing option. The pay-as-bid option would mean that Generator A could bid a higher price than Generator B in the electricity balancing market, for example. Even if both bids are accepted, each would only achieve the price they have bid, rather than the higher price bid by Generator A. Government discounted the pay-as-bid pricing option as it considered the risk of tactical bidding and the lowering of investor confidence to be too high.

The wholesale electricity price is currently the same throughout the UK, regardless of where the electricity comes from or where it is consumed. This arrangement results in several inefficiencies, including that the wholesale electricity price does not incentivise market participants to operate and locate in a way that is consistent with the physical needs of the network (i.e. energy is not generated where it is needed). These inefficiencies cause significant operational and grid balancing issues, such as increased network constraint costs (these are amounts that the System Operator pays generators to reduce their electricity output when electricity output exceeds network capacity (referred to as network congestion)).

Zonal pricing divides the network into several different zones or regions (typically determined by reference to the largest geographical area within which market participants can trade energy without network congestion) and assigns a single price for electricity in each zone. All generators within a particular zone receive the same price for their electricity, regardless of their location within the zone. Consumers within the same zone also pay the same price for their electricity. Zonal pricing is typically implemented when the network is not highly interconnected and generators and consumers are geographically dispersed.

Nodal pricing, on the other hand, divides the network into hundreds or thousands of nodes and assigns a different price for electricity at each individual location or node within the network. This means that the price of electricity can vary depending on where it is generated and where it is consumed. Nodal pricing considers the specific physical characteristics of the network, including the location of transmission lines and generators and the amount of congestion on the network.

Both zonal and nodal pricing potentially allow (at differing levels of granularity) for more efficient use of the network and can encourage generators to locate in areas where they can produce electricity more cheaply. Proponents of locational pricing also believe it will help to resolve network congestion and ensure the network operates more efficiently, reducing the costs of dealing with constraints.

The implementation of zonal and or nodal pricing is not, however, without potential challenges including (among others) that locational pricing is far more complex than the current national price system and requires a more sophisticated market design and infrastructure, which the System Operator will need to be equipped to manage. Furthermore, renewable energy generators such as solar and wind power cannot simply relocate to areas where electricity demand is greater as their location is determined primarily by weather conditions. Likewise, future dispatchable power generation with carbon capture, will also be similarly location-constrained due to the need for access to CO2 transport and storage infrastructure.

Nodal or not: One part of the sweeping package makes energy producers and investors especially nervous: nodal pricing. This would involve basing the U.K. electricity market on local pricing rather than the current national approach. The approach is already used in some U.S. markets, including California, and in New Zealand.

Do experts like the idea? Many energy economists consider it a good way to run a grid efficiently while getting value-for-money for electricity users. National Grid ESO backed the approach in its response to the REMA consultation.

In the Net Zero Strategy, the UK government committed to assessing whether broader reforms to electricity market and policies were required to deliver the decarbonisation and expansion of the electricity sector to enable us to meet our net zero commitment.

The Department for Business, Energy and Industrial Strategy (BEIS) has since set out five key future system challenges out to 2035, which are: investment; flexibility; location and networks; operability; and whole system flexibility. The Review of Electricity Market Arrangements (REMA) being carried out by BEIS aims to identify and implement the reforms needed to GB electricity markets, in order to drive the necessary investment in, and efficient operation of a secure, low carbon electricity system by 2035.

Like many markets, electricity pricing at a wholesale level is based on an implicit marginal pricing regime. That is to say that as supply and demand must be matched in real time, the price is set by the most expensive generation at that point, providing potentially large returns to other generators.

Way back in the mists of time, the majority of the cost of delivered electricity was the energy itself, with added cost for the wires needed to transport it. Over recent years the dreaded non-commodity costs have shouldered the burgeoning costs of changes to the costs of running the network and providing security to upstream investors.

This option looks to improve locational signals and encourage investment in generation where it is needed. The national price would be replaced with different prices depending on the zone or node. There is precedent for nodal pricing in the US, New Zealand and Singapore and for zonal pricing in the EU. Under nodal pricing, the price in each location reflects the locational value of electricity, taking into account the physical constraints of the network. Under zonal pricing, the network is divided into different zones, with the boundaries representing major network constraints. The intention would be to encourage more efficient use of the network and deployment of generation. 006ab0faaa