Large Energy Users – Summer 2022 update on electricity and heat market reforms

United KingdomScotland

Energy policymakers are in the midst of an intense phase of activity seeking to ensure the Great Britain energy market is fit for the energy transition and to respond to the many challenges being faced by the current market.

This is provoking much debate for organisations within the sector, but in addition all organisations who use substantial amounts of energy or who own or invest in sites where power is consumed in significant volumes should take note that many of the discussions and proposed reforms have a direct bearing on some of the key focus points we see in these areas. For example issues and changes in respect of (i) procuring new grid connections, (ii) procuring green power, and (iii) the commercial and sustainability opportunities from on-site generation and flexibility of power consumption are all very much in the mix.

In this Law-Now we provide a summary of these aspects likely to be of most relevance to high volume power consumers and associated sites.

Key Documents

A number of the most pressing proposals for reform have been pulled together in the Energy Bill introduced on 6 July 2022 (the “Energy Bill”); BEIS’ consultation kicking off its wide-ranging Review of Electricity Market Arrangements (the “REMA Consultation”), published on 18 July 2022; and most recently, as envisaged in the British Energy Security Strategy of 7 April 2022, BEIS and Ofgem’s Electricity Networks Strategic Framework paper on 4 August 2022 (the “Networks Strategy”) collating some of the key policy priorities for electricity networks.

Network constraints and connection timescales

For sites/consumers with large power requirements, (“Large Energy Users”) the cost, timescale and procurement strategy in respect of new connections to the distribution network are increasingly key aspects/obstacles in taking forward new developments.

Of relevance in this area, in recent times we have had confirmation of:

  • reduced connection charges in Distribution Network Operator (“DNO”) connection offers issued from April 2023,
  • an increase in “flexible” connection offers, and
  • more standardised “queue management” processes in respect of DNOs terminating accepted connection offers where works are not progressing.

However, increasingly substantial lead times for new connections to electricity networks remain a pressing issue. In the medium to long term the Networks Strategy identifies a range of measures that BEIS and Ofgem propose may help to address these challenges, including:

  • Reviewing and strengthening the standards (including timescales and penalties) and incentives applicable to DNOs when making connections to their networks;
  • Supporting industry on further reforms to the connections process, including unlocking unutilised capacity;
  • Reviewing the system planning functions at distribution level (performed by electricity distribution network operators, local authorities and others);
  • Developing processes between BEIS, Ofgem and the Future System Operator (an independent, holistic energy system planning entity to be introduced pursuant to Part 4 of the Energy Bill – see here for further details) in order to identify network constraints earlier and drive forward strategic network investments;
  • Working to provide earlier certainty to network operators on the network development projects that will be funded via their regulatory price controls and reduce the extent of the regulatory approvals required for such projects;
  • Streamlining the planning and consenting required for network development projects (both within and outside of the Nationally Significant Infrastructure Project regime);
  • Broadening the scope of competition in onshore electricity networks (see below); and
  • Driving greater flexibility in the electricity system (see below), including making greater use of “connect and manage arrangements”.

Location specific power costs and connection capacity visibility

It can be challenging in the early stages of a project for Large Energy Users to identify areas for development with the most favourable likely network connection costs and lead times. There have been calls across the electricity industry and its customers for more time to increase visibility of the nature and extent of the assets connected to the transmission and distribution networks and the areas with greater availability of connection capacity (see, for example, the recommendations of the Energy Data Taskforce in 2019, including proposals for a unified “Digital System Map”.)

Enhancing the way in which pricing structures in the electricity market reflect the availability of power/capacity on the system, and thereby send “locational incentives” in terms of where generation and demand connects into the network, is a key objective of the REMA Consultation.

In essence, pinch points in the GB electricity networks mean that it is not simply a case of power demand in a particular location being served by electricity provided from any part of the country. Instead, the need to balance generation and demand across the electricity system in real time combined with limited network capacity frequently leads to inefficient and expensive measures to curtail generation in certain areas and increase generation in other areas.

The speculative options on the table for increasing locational incentives include, at their most radical, the introduction of separate electricity wholesale markets for different regions or more granular zones, or additional markets balanced at the distribution level. This has the potential to lead to the wholesale cost of electricity varying by location – which could put a very different complexion on the ongoing power costs associated with a particular location choice for Large Energy Users.

The REMA Consultation also invokes less contentious measures such as the need for “greater co-ordination” between operators of transmission and distribution networks in order to “improve asset visibility”.

A further parallel avenue for strengthening locational signals in the REMA Consultation is network charging reform. Ofgem has, for some time, been working on adjustments to network charges, i.e. the portion of energy bills that contributes towards the cost of operating and maintaining electricity networks.

While a key aim of the REMA Consultation is to reduce the overall costs of participation in electricity markets, it is explicitly acknowledged that there are likely to be “winners and losers”. A number of the policies under consideration (such as dividing wholesale electricity markets into geographical areas) would increase the amounts spent on an ongoing basis by network users (likely to flow through to electricity consumers) at particular locations that present greater challenges to network operators. This would have the potential to have a substantial impact on Large Energy Users who have already developed, committed to or invested in projects in those locations prior to the introduction of any such policy.

Competition for onshore network projects

One particularly relevant feature of the power market in Great Britain for Large Energy Users is the limited number of options when procuring connections to electricity networks. Currently, persons applying for connections will generally be dependent on the incumbent monopoly operating either the national electricity transmission system (National Grid) or the regional electricity distribution system (the relevant DNO).

BEIS and Ofgem have, for a number of years, been working on introducing competition in the context of network connections. Since 2005, customers connecting to electricity distribution networks have been able to choose from a number of entities (known as “ICPs” and “IDNOs”) for the construction and operation of the “last mile” / “contestable” aspects of the infrastructure required for their connections.

The Energy Bill (section 153 and Schedule 12, proposing amendments to the Electricity Act 1989) paves the way for a comprehensive regime for competition in the build and operation of new larger scale high value network projects. The regime proposed in the draft legislation is wide-ranging in its scope, covering projects relating to electricity transmission and distribution projects. The Energy Bill envisages the appointment of a delivery body (or bodies) to administer competitive tenders for relevant network projects.

While the details of the regime are yet to be introduced, Large Energy Users will appreciate the direction of travel. It is anticipated that the involvement of a broader range of private sector participants in the development of onshore electricity networks will unlock the greater creativity and resources required to deliver the volume of network reinforcements needed for the energy transition. You can read more about the proposed onshore competition regime here.

Low-carbon flexibility

Another key policy objective for BEIS, prominent in both the Energy Bill and REMA Consultation, is the need ensure sufficient low-carbon electricity system flexibility (i.e. the extent to which generators and demand users can actively manage the times at which they import and/or export electricity) in light of the magnitude of the increase in renewable generation and decentralisation required for the energy transition.

This has been a very active workstream for the Government and Ofgem since their Smart Systems and Flexibility Plan in 2017 (as updated in 2018) and follow-up plan in 2021.

Given policymakers’ intense focus on incentivising flexibility, on-site power solutions such as small-scale generation and energy storage, together with demand management and energy efficiency measures, are likely to become increasingly attractive to Large Energy Users. Our CMS Guide to On-site Power Solutions provides an overview of some of the key opportunities and risks in this regard.

Less positively for on-site generation and storage business models, it should however be noted that REMA stresses that the government has committed to ’rebalancing’ energy bills towards reducing the costs of funding electricity policies (such as the Contracts for Difference regime and the Energy Company Obligation) that are currently borne by electricity suppliers and passed through to consumers in their electricity bills. Given the business model for on-site power assets is often partly predicated on the costs avoided versus supply of electricity from the grid, the impact of a reduction in the costs included in electricity bills should be borne in mind and may be unhelpful.

Regulation of heat networks

Regulation of the distribution and supply of networked heating and cooling has been anticipated for a number of years, in particular since the CMA’s heat networks market study in 2017-18. While legislation was introduced on heat network metering and billing in 2014, these activities have otherwise remained largely unregulated.

Part 7 of the Energy Bill now heralds the introduction of a licensing regime for heat suppliers and network operators, administered by Ofgem. The regime will provide for certain “regulated activities” with respect to the supply and distribution of heat or cooling via networks to multiple premises. It is likely that the regime will prohibit the carrying out of such activities without a licence, even for persons that have previously done so. By subjecting these activities to greater scrutiny, the aspiration is to achieve greater consistency in pricing and levels of service in heat provision.

The draft legislation also lays the groundwork for a zoning regime, creating an obligation for certain premises within designated zones to connect to their local heat networks in order to facilitate larger-scale heat networks for wider areas.

Large energy users considering and/or putting in place arrangements for relevant heating and cooling networks should assess how to appropriately reflect these known upcoming regulatory changes in their approach and documentation.

Next steps

The Energy Bill was introduced in the House of Lords, where detailed committee scrutiny is due to begin on 5 September 2022.

The REMA Consultation poses 74 questions to stakeholders. BEIS is seeking responses by 10 October 2022. Following the consultation, BEIS envisages that it will work with stakeholders to develop the options and determine the necessary reforms throughout 2022-23 and establish and deliver a full delivery plan “from the mid-2020s”. Central to BEIS’ stated approach is their recognition of the need to ensure investor confidence in electricity market regimes in order to ensure deliverability of critical projects at the lowest cost – it is likely, therefore, that stakeholder consultation over the coming years will be extensive.

While no overall timescale is set for the implementation of the measures identified in the Networks Strategy, it is clear from the document that such implementation is seen as urgent in order to facilitate broader policy objectives over the coming years.