Supplementary written evidence submitted by the Climate Change Committee (POW0112)

How do we decide at present how much capacity is needed in the system, and how will this calculation change over the next decade?

Planning of capacity requirements for the electricity system is currently primarily the responsibility of the Government, through the Department of Net Zero and Energy Security (DESNZ). Other organisations have a role, including the National Grid Electricity System Operator (NG ESO), soon to become the National Energy System Operator (NESO).[1]

The Government currently contracts the majority of new renewables developments centrally through the annual auctions for Contracts for Difference. Nuclear capacity is also coordinated centrally given the large size of individual projects. And in addition, for ensuring security of supply, the Government runs auctions through the Capacity Market, buying capacity for one year ahead and four years ahead to ensure that peak demand for electricity can be met with a certain degree of confidence.[2]

The amount of capacity to be contracted through these policies is determined through a range of processes. Some technologies have Government targets for deployment which need to be taken into account (e.g. the Government is aiming for up to 50 GW of offshore wind by 2030[3]). The Government undertakes its own internal modelling of capacity requirements. Other assessments also inform the process, in particular NG ESO’s Electricity Capacity Report[4] which feeds into Government decisions on the Capacity Market.

It is not clear that these processes need to change significantly over the next decade, but refinements to policies and processes will be needed to ensure they are consistent with Net Zero. The Government is already taking steps towards this through their Review of Electricity Market Arrangements and launched a consultation on a range of options on March 12 2024.[5]

Some key steps that are needed include developing a strategic view of what capacity mix is required for a decarbonised system. This should not be a prescriptive approach to picking winners, but to understand the level and types of capacity required that deliver reliable supplies of electricity under different weather conditions and fit within carbon budgets for the whole economy under different decarbonisation pathways. This can then be used to inform policy development and ensure policies are in place and/or adjusted in order to deliver the right level – and types – of future capacity.

If the system is becoming more complex, how will the system operator need to change to accommodate this?

Power system operation has always been complex and subject to uncertainties, such as the availability of generating plant and the level of demand, but is becoming more challenging. There are many more individual sources of power than in the past. A large proportion of the UK’s generation capacity (21% in 2022[6]) is based on variable renewables – wind, solar and hydro power – for which the available output over the upcoming days or hours is uncertain. Furthermore, a growing proportion of capacity in Britain – up from 21% in 2013 to 35% in 2020 – is connected to one of the lower voltage distribution networks rather than the high voltage, national transmission network and therefore not normally directly observable and controllable by the system operator[7]. Finally, all wind and solar generation, which is a growing proportion of generation capacity, uses ‘asynchronous’ rather than the ‘synchronous’ electrical technology that is much more familiar to the system operator.[8]

‘Asynchronous’ technology is very flexible in how it can be controlled. Quite how to specify each installation’s controls in order to guarantee that their interactions are always beneficial to overall system stability is something that system operators around the world are learning, and need to learn. As ‘synchronous’ power plant that uses fossil fuels is used less and less, system operators also need to learn how to use alternative means to provide flexible ‘ancillary services’ that are used to ensure that the system operates in a stable manner when subject to disturbances such as faults on generators or branches of the network. These alternatives include use of wind farms, batteries and ‘flexible demand’ such as ‘smart’ electric vehicle charging or, in future, electrolysers used to manufacture hydrogen using electricity and water. In order to make use of these new sources of flexibility, it is likely that the national transmission system operator, the distribution network operators and aggregators of ancillary services will need new system monitoring and control facilities and decision support software, i.e. enhanced ‘digitalisation’[9]. It has also been argued by some, e.g. NG ESO, that reform of the electricity wholesale market is needed to promote the availability and efficient utilisation of ‘flexibility’[10].

Interconnectors between Britain and neighbouring countries also use ‘asynchronous’ technology in the form of high voltage direct current (HVDC). Interconnection with other countries provides benefits such as access to electricity when wind speeds are low in Britain, and buyers of surplus low-carbon energy when wind speeds are high. However, there are also uncertainties around quite how the interconnected electricity markets will interact in future.[11]

Would bringing in more technology-specific deployment targets help our future energy security?

Moving to a decarbonised energy system, with renewables providing the majority of electricity production backed-up by a portfolio of low-carbon flexibility options, would maintain energy security and reduce the UK’s dependence on imported oil and gas. In turn, this would help reduce the UK’s exposure to volatile international prices.

The Government already has a number of technology-specific deployment targets, including for offshore wind, solar, and nuclear. These need to be complemented by other resources that ensure the reliable meeting of demand for electricity year-round.

A number of options provide capabilities that are broadly interchangeable in terms of the electricity system and its operation, e.g. nuclear power and relatively inflexible generation based on natural gas with post-combustion carbon capture and storage (CCS), or gas with pre-combustion CCS versus generation using hydrogen from a long-duration store. However, these have different characteristics in terms of, for example, infrastructure needs and costs that are yet to be fully revealed by the market. The aim should therefore not be to fully centrally plan the future capacity mix down to the level of individual technologies. Nevertheless, there could be value in giving clear signals to investors, of the types of technologies required in future (e.g. long-duration storage), of the levels these may need to be deployed at, and the need for supporting infrastructure. This could help reduce uncertainty and risk, which can help reduce costs. And it could provide a wider signal of the need to develop and build-up supply chains.

Any targets must also strike a balance between ambition and achievability, and must be backed-up by sufficient policy action, such as appropriate market mechanisms, to ensure that they are delivered in practice.

March 2024