Great Britain currently has a single, national wholesale electricity price which does not vary by location. In some other countries, such as Australia, Italy and Sweden, wholesale electricity markets are divided into regional price zones, while in others such as New Zealand, Singapore and some US states, more granular zones are used. These models are called zonal or nodal pricing and are known as forms of ‘locational pricing’, as they take the levels of energy supply and demand in a particular location into account when setting the price.

According to the National Energy System Operator (NESO), Great Britain’s national pricing model ‘does not take network constraints into consideration’, providing the same price of electricity regardless of whether there is sufficient network capacity to transport it to where it is needed. This can mean that the price of electricity may not reflect the actual cost of delivering it to different locations.

Under the current arrangements, if there is insufficient network capacity to move generation to end consumers, the system operator must instruct generators whose electricity cannot be transported to curtail their output and compensate them for doing so. The system operator then has to pay generators closer to consumers to increase capacity so that overall demand can still be met. The costs of these payments are ultimately passed on to consumers.

Wholesale prices do not form the entirety of consumer energy bills. A number of other costs are also placed on consumer bills, including network charges and the costs of energy policies, such as subsidising renewable energy generation through Contracts for Difference (CfDs).

Network charges paid by users of the transmission network – known as Transmission Network Use of System (TNUoS) charges – currently provide some locational signals, with transmission-connected generators and consumers located in areas closer to demand sometimes having a lower tariff for transporting energy and potentially receiving negative charges, or ‘credit’, for using the electricity network efficiently.

This Committee believes that, on balance, stronger price signals are required to encourage a closer location of generation and demand, reducing the amount of grid that needs to be built.

In April 2022, the government launched a review of electricity market arrangements (commonly referred to as REMA), aiming to adapt electricity market arrangements which were established ‘in an era of large, centralised, fossil fuel-based generation’ to an increasingly low-carbon, renewable system. As part of the review, the government has been exploring proposals to increase locational signals in electricity markets, including a potential move from national pricing to locational pricing.

Following an initial consultation as part of the review, the government stated that, if locational pricing was introduced, it would be in the form of zonal pricing, which would split Great Britain into several regional zones that would each have their own electricity price. The government ruled out the possibility of nodal pricing, arguing that this level of granularity would possibly have an adverse impact on investor confidence.

In theory, zonal pricing would lower the price of electricity in areas of excess supply – aiming to incentivise consumers, particularly large energy-intensive businesses, to locate closer to generators. Conversely, areas of high demand and low supply would have higher prices, incentivising electricity generators to build additional supply there. The aim of this reform would be to reduce the waste of excess renewable generation that the grid cannot transport elsewhere and decrease the need for additional grid expansion by locating generators and energy-intensive consumers closer to one another. This would aim to contribute to a reduction in system costs and lower bills for consumers.

Maintaining current arrangements are ‘not an option’
In an update in December 2024, the government indicated that it would make a final decision on wholesale market reform by mid-2025. The update indicated that maintaining current arrangements was ‘not an option’, and that the government would proceed with either zonal pricing or ‘reformed national pricing’, which would include a strengthening of locational signals through network charges.

Witnesses to this inquiry could see benefits in a move to zonal pricing, but there was hesitance about the potential impact of such a significant change on investor confidence. In some cases, generators and energy-intensive industries made clear to us that they have a limited ability to change locations in response to price signals and were concerned about adverse impacts, such as an increase in the cost of capital for generators and higher electricity prices in some regions for consumers.

This Committee believes that, on balance, stronger price signals are required to encourage a closer location of generation and demand, reducing the amount of grid that needs to be built. Zonal pricing and reformed transmission network charges should enable better use of existing grid capacity and lower the cost of electricity, provided that the transition and its risks are managed well.

If the government introduces zonal pricing to wholesale electricity markets, it must take action to address the investor uncertainty that this could cause. We welcome the government’s indication that it will make a decision on wholesale market reform by the middle of 2025. It is crucial that the government provides clarity soon in order to encourage the level of investment needed to meet the clean power target.

If zonal pricing is to be introduced, the government should publish an assessment of the adverse impact on generators and companies that cannot move to take advantage of lower electricity prices elsewhere. In that event, the government should provide clarity on the transitional support which adversely affected generators and consumers will receive. Also, Ofgem should review its framework for network charges, with a view to providing stronger locational signals to energy generators and energy-intensive industries.

This article is an edited extract from the report Power struggle: Delivering Great Britain’s electricity grid infrastructure published by the House of Lords Industrial and Regulators Committee. This particular section specifically cited evidence given by Octopus Energy’s Rachel Fletcher, Energy UK’s Charles Wood, Ofgem’s Akshay Kaul, NESO’s Kayte O’Neil, EDF Energy’s Matthew Ball, Frank Aaskov of UK Steel, Teodora Kaneva of techUK, Andy Manning of Citizen’s Advice, Electricity Networks Commissioner Nick Winser, SSEN Transmission’s Jessica Hardwick, Michael Shanks MP, Zenobe Energy, Field Energy, Energy Systems Catapult and Green Alliance.

The views and opinions expressed in this article are strictly those of the Committee only and are not necessarily given or endorsed by or on behalf of the Energy Institute.

• Further reading: ‘A country divided: exploring the pros and cons of zonal electricity pricing’. A war of words has broken out in the electricity industry about whether to split Great Britain’s electricity market into smaller zones, in the hope of reducing costs and making more efficient use of renewables. Janet Wood explores the current complex situation, and how we got here.
• The introduction of zonal electricity pricing should come after the transmission grid has been upgraded to deal with a future zero carbon electricity system, argue Will Blyth, from Oxford Energy Associates and Callum MacIver, from Strathclyde University; both also work at the UK Energy Research Centre (UKERC).