One night last week I had a dream that hydro-power isn’t generated by water, but by a mouse called Lucy which is getting tired, with dire consequences for the market. The dream made more sense than the tangle which is known as network charging reform.

Back in 2016, Ofgem decided that the way in which electricity networks are accessed and paid for required investigation and potential reform. It began by reviewing so-called “embedded benefits” in 2017, and the following year it launched a Targeted Charging Review (“TCR”) which examined the way in which residual network charges are recovered, and in 2018 it launched a Significant Code Review (“SCR”) into the recovery of forward-looking charges as well as network access. Then in early 2022, Ofgem removed the charging aspects of the SCR, creating a new SCR into distribution charging with a new timetable, and a Task Force into transmission charging.

Network charges have risen considerably in recent years and by August 2021 (before the increase in wholesale prices) had reached 23% of bills. Changes in the types and location of generators during the energy transition have also changed over the same period, in ways that were not anticipated when the charges were designed. In particular, small generators connected to distribution networks – historically a small group – had risen in number and were benefitting from charging exemptions that were no longer appropriate. They were also being used by suppliers to help them to reduce their share of network costs in a way that did not reflect the actual benefits they had on the networks. These were all good reasons for the charges and their methods of recovery to be reviewed and revised.

However, many in the industry felt that Ofgem’s approach of addressing residual costs ahead of forward-looking costs made little sense, a stance it took based on its belief that aspects of the residual costs regime were distorting the market to such an extent this should be a priority. That might not have mattered had the reviews been carried out swiftly, but the entire exercise has been beset by delays and changes to the scope of Ofgem’s programme of work, creating confusion for market participants who have sometimes struggled to keep track of the different consultations, decisions and spin-off projects. In this post I will try to summarise the state of play, identify firm decisions and their implementation times, and provide an update on ancillary and spin-off work.

What are network charges and why are they important?

Great Britain has two types of electricity networks: the high voltage transmission system, and the lower voltage distribution networks. Various costs are associated with this infrastructure: clearly, networks need to be built and maintained so the capital and operating costs of wires, pylons, transformers, substations and so on need to be recovered. Providing new connections to these networks can also cost money, particularly if a new source of demand or supply is likely to overload existing infrastructure requiring additional capacity to be built. Electricity is also lost as it moves across networks: transmission losses account for 2% of transmitted electricity, whereas distribution losses account for 8% on average. These losses arise due to technical reasons relating to the physics of electricity transmission and distribution, due to engineering decisions made such as the sizes of cables and transformers. Non-technical reasons for losses include theft, measurement inaccuracies and timing differences.

The voltage of the electricity networks also needs to be maintained within a stable range, with the transmission system operator, National Grid ESO, having a duty under its transmission licence to ensure that the system frequency remains within 1% of 50 Hz. To achieve this, supply and demand need to be balanced in real time, and these balancing activities also incur costs.

All of these costs must be recovered from users of the networks, whether that is generators or consumers, and over time these costs have grown considerably, reaching 23% of bills in 2021.

Because networks are monopolies (we don’t have multiple wires from different providers connecting to our homes and businesses) their activities are regulated, with Ofgem setting out rules around how and when network investments should be made, encouraging network operators to minimise costs for consumers. For example, operators are incentivised to consider alternatives to simply building new network capacity by operating existing infrastructure in a more flexible way.

However, with the expected electrification of significant amounts of heating and transport demand, and the growth in small distributed generation and storage, both the size of networks and the way in which they are used is changing. Ofgem’s various network access and charging initiatives were designed to ensure that these changes are managed in a way that minimises costs for consumers, avoids creating market distortions, and does not distribute costs unfairly.

Historically, network charges have been divided into three main areas: Transmission Use of System Charges (“TNUoS”), Balancing Services Use of System Charges (“BSUoS”) and Distribution Use of System Charges (“DUoS”), which worked as follows:

Transmission Use of System Charges (“TNUoS”)

TNUoS charges provide the allowed revenue (under the price control scheme known as RIIO) for transmission owners to recover the cost of building and maintaining transmission infrastructure. The tariffs were intended to be reflective of the cost of using the network to help network users make efficient decisions about where and when to use the network. TNUoS charges were historically broken down in three ways:

• The Locational Charge (Wider TNUoS) – calculated by the Transport model – which reflected the incremental cost of power being added to the system at different geographical points;
• The Residual Charge (Wider TNUoS) – what is not recovered under the Locational charge is recovered in this charge so that the Transmission Owners recover their total allowed revenue; and
• The Local Circuit Charge (Local Circuit TNUoS) and Substation Charge (Local Substation TNUoS) which were both only paid by generation.

Half hourly metered consumers were charged according to their demand over the three ‘Triad’ periods each year (the half hours with the highest demand, subject to a 10 day separation) with a £/kW tariff, while non-half-hourly metered consumers were charged based on their annual consumption between 4 and 7pm (in kWh), through a p/kWh tariff. TNUoS tariffs were set a year in advance, with charges subsequently reconciled to actual usage.

The residual component of TNUoS – the difference between the income allowed under the price control and the amount recovered under forward-looking charging – was applied in a uniform way across GB, while the forward-looking element varied by the 14 demand zones. Generators are charged according to their “TEC” (Transmission Entry Capacity), while suppliers are charged based on demand. All tariffs are based on the geographical zone to which users are connected.

TNUoS tariffs are published annually by 31 January and take effect from 1 April each year.

Balancing Services Use of System Charges (“BSUoS”)

BSUoS costs reflect the costs of balancing the transmission system, including running the control room, the cost of frequency response arrangements and other ancillary services, and constraint costs. BSUoS was historically charged on a half-hourly volumetric basis (£ /MWh) set ex post and was paid by both generation and demand, except for interconnectors which had been exempt since 2012. Unlike TNUoS, BSUoS was the same regardless of location, and was paid 50% by generators and 50% by consumers.

Distribution Use of System Charges (“DUoS”)

DUoS charges provide the allowed revenues for distribution system owners to recover the cost of building and maintaining distribution infrastructure. Charges were set based on the voltage at which users were connected, with the Common Distribution Charging Methodology (“CDCM”) covering charges to HV and LV customers, and the EHV Distribution Charging Methodology (“EDCM”) covering charges to larger customers connected to the extra-high voltage levels (22 kV or above).

Part of the DUoS charge was levied as a flat rate per meter per day, and part was volumetric, with the tariff depending on the time of day and day of the week, in bands, with the periods of highest demand attracting the highest prices. The exact times for each band varied across the distribution networks. Under the CDCM, there were Red (high), Amber (medium), Green (low) bands for HH metered customers and Black/Yellow/Green for NHH metered customers. Under the EDCM, consumers paid a fixed daily charge per meter, a fixed daily capacity charge based on the size of the connection, and a volumetric charge for consumption in the Super Red Band period.

In April 2018, the price variation of the CDCM bands was reduced: Red Band tariffs were lowered, and Amber and Green tariffs raised, narrowing the differentials between them.

Changing TNUoS

Removal of embedded benefits

One of the first things to change was the removal of so-called “embedded benefits” – prior to Ofgem’s 2017 review, residual TNUoS charges were levied on net demand, so any generation connected to (or “embedded in”) the distribution network was treated as negative transmission system demand. Suppliers, who take electricity from the transmission system in order to deliver it to consumers, were able to reduce their exposure to TNUoS by purchasing embedded generation, lowering the amount they needed to offtake from the transmission network. The resulting reduction in the TNUoS charge was known as the “embedded benefit” and was usually shared between the supplier and the generator.

Ofgem believed that this benefit was inappropriate because the existence of embedded generation did not reduce the amount of residual TNUoS cost that was being recovered in this way: the methodology allowed some suppliers to reduce their share of the cost but it did not reduce the cost overall. It therefore acted early to remove this benefit by making the residual TNUoS charge dependent on gross rather than net demand. This was a highly unpopular decision, which was unsuccessfully challenged in the courts.

This change was phased in over 3 years beginning on 1 April 2018, applying to all small (sub-100 MW) embedded generation commissioned after 30 June 2017, and all small embedded generation with a Capacity Market contract. Avoided Grid Supply Point costs attributable to the generator could be paid.

The TCR introduced a similar change for the recovery of non-locational BSUoS charges, with this change coming in from 1 April 2021.

Removal of the Transmission Generation Residual charges

The transmission residual charges were historically levied on both demand and generation, through the Transmission Demand Residual (“TDR”) and the Transmission Generation Residual (“TGR”) charges. Over time, the TGR charge became negative and was therefore a benefit to all generators which received it. Ofgem decided this benefit was not justified and decided that the residual payments would only be recovered from demand.

This change took effect in April 2021, however there was a spanner thrown into the works when in May 2022, the High Court rejected portions of the modifications to the Connection and Use of System Code (“CUSC”) which were designed to give effect to this decision. Ofgem has requested permission to appeal this decision, but, having read the judgement, I think this would be unlikely since it would mean that the judge had made an error in law. The details of the issue are described in the CMA’s original rejection of SSE’s appeal against the CUSC modifications in question, which it had to partially reverse following the court’s judgement.

Ofgem is considering the next steps, but does not currently anticipate asking National Grid ESO to change the TNUoS tariffs for 2022/23.

Levying the transmission residual charge on a fixed rather than volumetric basis

In addition to levying the transmission residual charge (TDR) only on demand rather than demand and generation, Ofgem decided that the charge should be levied on a fixed rather than volumetric basis, with a series of fixed charging bands set for all of GB for non-domestic consumers. As part of its code modification proposals to deal with the implementation of the TDR, NG ESO proposed flooring any negative TNUoS forward-looking charge at 0, with four charging bands for transmission-connected consumers, and delaying implementation by a year to take effect from 1 April 2023. This proposal was accepted by Ofgem in March 2022.

This change was originally due to take effect from April 2021 but was delayed by 1 year to April 2022, and this latest delay, means that Winter 2022/23 will be the last in which Triads will be used as a basis for determining TNUoS charges.

National Grid ESO’s TNUoS charges for 2022/23 can be found here, and its 5-year TNUoS forecasts are here. The implications of the judicial review have yet to be incorporated.

Forward-looking charging

Forward-looking TNUoS charges were originally within the scope of the SCR, but have since been removed and are now subject to new Task Forces, that are currently being established (see below). In addition, the implementation of fixed demand residual charging had a relationship to forward-looking charging in the case of negative forward-looking charging components, so will be floored at zero as noted above.

TNUoS Task Forces

Ofgem has asked NG ESO to establish Task Forces to examine two main areas:

• The root causes of the unpredictability of TNUoS charges and how these might be addressed; and
• The input data into the current model used to calculate the locational element of TNUoS to ensure charges remain cost reflective, considering the inherent trade-off between improving predictability and cost reflectivity.

There are significant areas which Ofgem believes should be considered by the Task Forces, including:

1. Reviewing the data inputs into the current locational TNUoS methodology to identify and quantify their effect on the predictability of TNUoS tariffs as a long- run investment signal, suggesting improvements as deemed necessary.
2. The calculation of the wider TNUoS charge components (exclusive of the ‘Adjustment Tariff’ used to support compliance with the Limiting Regulation), and the approach to zoning.
3. How closely the TNUoS methodology should align with the ‘real world’ operation of the transmission system (in the context of the intention of TNUoS being to provide a long-run marginal cost signal, not a short-run or operational signal).
4. Identification, consideration, and suggestions/recommendations of new inputs into the TNUoS locational methodology (eg signalling excess/insufficient capacity).
5. Existing data inputs such as Charging Bases and Error Margin Calculations.
6. Determining which elements of TNUoS charges should be paid by distributed generators with a clear, system-based rationale for any differences in treatment between classes of generators.
7. Appropriate treatment of island connections, and some Offshore developments including (solely in this context) the definition of a MITS Node, with consequential consideration of appropriate zoning methodologies for islands and Offshore (notwithstanding the longer-term position is subject to change in the context of other potential market reforms).
8. Determining any changes which will simplify the methodology and make it more approachable to new market participants

Any changes arising from the work of the Task Forces are likely to be implemented in 2024-26, however, the use of Task Forces instead of an SCR is designed to allow changes to be introduced more quickly should consensus on particular areas emerge (under an SCR, changes cannot be made until the completion of the SCR process).

Ofgem is also planning its own, longer-term programme of work that will look at TNUoS in the context of potential broader reform to the electricity markets, the changing energy landscape, and Net Zero requirements, although to date there is little information on the form this will take.

Changes to BSUoS

In addition to levying BSUoS charges based on net rather than gross demand as noted above, the TCR identified further issues with BSUoS charging and established a BSUoS Task Force (known as the Second BSUoS Task Force) to determine who should pay balancing services charges and how these charges should be recovered. This new task force would build on the work of a previous task force which had determined that it would not be “feasible to charge any of the components of BSUoS in a more cost-reflective and forward-looking manner that would effectively influence user behaviour that would help the system and/or lower costs to customers. Therefore, the costs included within BSUoS should all be treated on a cost-recovery basis.”

The Second BSUoS Task Force recommend that “final demand” should pay all Balancing Services charges, and that the charge should be levied as a volumetric fixed charge, and that the total length of the fix and notice period should be around 14/15 months in length. Ofgem accepted these proposals in principle but determined that more work was needed to consider the costs and benefits. In April 2022, Ofgem approved CUSC Modification CMP308 which will apply BSUoS to final demand only from 1 April 2023.

Two further code modifications (CMP361 and CMP362) have been proposed to implement the change in the charging basis to an ex ante fixed volumetric tariff set over a total fixed and notice period of 15 months. Ofgem has yet to approve these modifications.

The application of BSUoS to final demand only removes another embedded benefit since embedded generators do not currently pay the charge but transmission-connected generators do. Not only did this provide an advantage to embedded generators in the wholesale markets, it also enabled them to submit lower bids in the Capacity Market, which Ofgem considered to be distorting effects. Behind-the-meter generators will still benefit under the new cost recovery approach, but Ofgem considers that other areas of market distortion are a higher priority. It will monitor the situation and may seek to make further adjustments in future.

Changes to DUoS

The TDR determined that for the recovery of residual distribution charges, domestic consumers will pay a single residual charge set for each licensed area, and non-domestic consumers will be charged on the basis of a set of fixed charging bands also set for each distribution area. Transmission-connected consumers will pay transmission residual charges, while distribution-connected consumers will pay both transmission and distribution residual charges.

Unlike the change to the TDR, the implementation of the change to the residual distribution charges has not been delayed and was implemented in April 2022.

The SCR launched in 2018 originally included a “wide-ranging review” of DUoS charging. The decision to remove this from the original SCR and create a new DUoS SCR is largely procedural in nature, as it would allow the Access SCR to conclude with a single direction while providing a means of progressing the DUoS review separately. The overall objective for the DUoS review remains unchanged: to ensure electricity networks are used efficiently and flexibly, reflecting users’ needs and allowing consumers to benefit from new technologies and services while avoiding unnecessary costs on energy bills in general. This review will include, among other things:

• A review of the charging methodologies for Extra-High Voltage (EHV), as well as High Voltage/Low Voltage (HV/LV)
• The balance between usage-based and capacity-based charges, as well as charges that could vary by time-of-use
• Improvements to signals about how network costs and benefits vary by location
• Improved predictability of charges for EHV users
• The potential need for mitigating measures such as a basic charging threshold to protect small users (and vulnerable customers) from sharper charging signals

While the DUoS SCR will retain the relevant work from the Access SCR, Ofgem does not expect any changes to be implemented before 2025. The previous work was set out in the Summer 2019 working paper and in the shortlisted policy options open letter of March 2020. In addition to changes in calculation methodology, Ofgem is considering basing DUoS charges on more accurate time of use bands (eg seasonal), charges based on agreed capacity rights, or hybrid options of the two.

Network charging reform is important and should not be treated so casually

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The energy transition is involving significant increases to network charges: by August 2021, before the hike in wholesale prices, network charges had grown to 23% of electricity bills.

All aspects of the charges have been growing as new types of generation have been connecting to new parts of the network, and the growth in intermittent generation has made balancing more difficult and therefore more expensive.

But Ofgem’s approach to these changes has been beset by delays and changes of direction, and legal challenges, all of which have created uncertainty for market participants.

It has been very difficult to find comprehensive information about these changes – Ofgem would do well to summarise its work in an easy-to-digest format for the many smaller market participants that lack the resources to be directly involved in the change processes.

Preparation of this blog was not straightforward, and it is difficult to be confident that the information is fully comprehensive and reflects the most recent positions – if any readers are aware of any further changes to network charging I would welcome their input and will update this blog accordingly.

Ofgem has been widely criticised for its regulatory failures in the retail segment, and while its chaotic approach to network charging has not attracted the same degree of scrutiny, it has been no more successful in this area of its remit. The regulator needs to get a grip if the energy transition is to progress smoothly.