It’s now six years since Ofgem commenced a major overhaul of network charging that was initially split between two significant code reviews (SCRs).
The first, launched in June 2017, focused on residual charges and embedded benefits, while the second, launched the following summer, examined forward-looking charges and network access arrangements.
In principle, forward-looking charges are intended to reflect users’ impacts on future network investment depending on where they connect and how they use the network. Residual charges, by contrast, are designed to recover the already sunk costs of the existing network and are not intended to be cost-reflective.
Ofgem said the overhaul would ensure that networks charges provide the right price signals to users to connect to and utilise electricity networks in a way that minimises overall costs.
The regulator said this would be necessary to realise the many billions of pounds of potential savings that could achieved by managing network constraints using flexibility. It said this would only become more important as devices such as electric vehicles and heat pumps become commonplace in peoples’ homes and huge volumes of renewable generation come online, putting a growing strain on Britain’s aging infrastructure.
The controversial residual charges review concluded in November 2019, with Ofgem deciding to apply the charges as fixed, banded fees levied solely on consumers. It also opted to replace triad avoidance payments – one of several “embedded benefits” available to distributed generators – with a much smaller embedded export tariff.
The second review eventually concluded two-and-half years later in May 2022. Among other things, Ofgem decided to reduce distribution connection charges by removing the requirement for customers to contribute towards the cost of wider network reinforcements.
However, by this point the scope of the second review had substantially narrowed. In its minded-to decision in June 2021, Ofgem announced it was pausing work on forward-looking DUoS charges, and the following November, Ofgem proposed to descope this work entirely and launch third separate SCR dedicated to DUoS charges. In February 2022, the regulator confirmed the decision and the launched spin-off.
Around the same time, its work on forward-looking Transmission Networks Use of System (TNUoS) charges was similarly transferred to a new TNUoS taskforce.
But then in November last year, amidst the ongoing energy crisis, Ofgem paused work on the DUoS review to enable it to focus on enacting the previously confirmed changes to residual and distribution connection charges.
The regulator said this was necessary to implement the reforms by the beginning of the RIIO ED2 price controls in April. With the changes made and the winter gone, Ofgem announced in May that it was resuming the DUoS review.
Caroline Bragg, interim chief executive at the Association for Decentralised Energy, says this long-running saga has been more than a little frustrating. Ofgem originally intended to make changes to forward-looking and residual charges alongside each other but these plans failed to materialise. More than half a decade after setting off down the road, the regulator appears to have decided to “step back and think about it from first principles again.”
Any changes to DUoS charges will now need to fit around its previous decisions in other areas. On the reduction in distribution connection charges, says Bragg: “Ofgem knew in doing that, and they were always quite explicit, they would take away a locational signal that would form a big part of the considerations around what the cost-reflective side of DUoS needs to look at.”
Meanwhile, the reforms to residual charges mean: “You’ve now got this big, fixed charge right there and it doesn’t matter what you do, you’ve still got to pay that.”
As much as possible, Bragg says reforms to DUoS charges need to be considered holistically alongside other network charges and wider energy market arrangements: “I guess one of the frustrations that we’ve always had a little bit is I think that the discussion around the role of network charging and providing locational signals and time-of-use signals has been quite separated and quite distinct from what else is going on in the market and what else is looking to send those signals.”
In this regard, Bragg has two interconnected concerns: differences in the arrangements at the transmission and distribution levels, and how DUoS charges interact with other types of price signals.
Background: Current price signals across transmission and distribution
TNUoS charges for generators are now entirely forward-looking and locational. They include wider locational tariffs across 27 zones around the country, local onshore substation and circuit tariffs, and local offshore tariffs. The wider tariffs are negative in some zones, meaning generators receive a credit.
Demand users are subject to both residual and locational forward-looking TNUoS charges, with latter depending on which of the 14 DNO licence areas they fall within. Distributed generators, which are seen as a reduction in demand at the transmission level, can also receive an Embedded Export Tariff. This likewise varies according to the distribution network they are connected to.
The Electricity System Operator (ESO) at National Grid manages transmission network constraints through the Balancing Mechanism. There are currently no flexible connections, although the ESO recently announced plans to introduce these for battery storage.
DUoS charges are calculated using two different charging methodologies depending on the voltage level at which users are connected. Both incorporate forward-looking and residual charges.
As demand has historically exceeded generation at the distribution level and distributed generators are therefore considered to reduce pressure on distribution networks, their net DUoS charges are negative (or zero) meaning they receive credits.
Users connected to high and low-voltage networks are subject to the Common Distribution Charging Methodology. The charges vary between DNO licence areas but there is no locational variation within each area. However, there are some time-of-use charges, which vary between green, amber and red time bands. The red band covers periods of peak demand.
Users connected to extra-voltage networks are subject to the Extra High Voltage Distribution Charging Methodology. The charges vary locationally, both between and within DNO licence areas, with generators’ credits mirroring the charges on demand users. There are also time-of-use charges, with demand users paying an additional charge during ‘super-red’ periods of peak demand and generators’ receiving credits for producing during these periods.
DNOs manage network constraints through flexibility tenders and flexible connections. The latter allows users to obtain connections cheaper and more quickly that would otherwise be the case. In exchange, they are subject to curtailment through Active Network Management (ANM) systems.
In terms of providing locational price signals about where to connect, Bragg is sceptical about the extent to which prospective network users can respond to those signals, especially at the distribution level.
“Storage can to some extent decide where it locates,” she explains. “It can do that across the country and it can do that to some extent with a DNO area.
“If you think about it in that way, providing long-run marginal cost locational signals is useful, particularly if you’ve made the connection boundary shallower.”
But she questions whether generators such as wind and solar farms, which have much more limited choice of potential sites, and demands users in particular, can respond to locational signals in the same way. On balance, she says there is a case for DUoS charges to provide some “weak” locational price signals.
Her bigger concern is how prices signals, including network charges, are used to manage network constraints over operational timeframes, and how these arrangements differ between transmission and distribution.
“The terms of connection at distribution are very, very different from the terms of connection at transmission,” she explains.
“I think ANM, whilst I do appreciate how useful it’s been in connecting lots of things quickly, doesn’t value that curtailment in close to real time. I feel for that reason, it’s a poor relative of what we’ve managed to achieve in the Balancing Mechanism, which does at least value constraints at the point at which you’re trying to constrain it.”
“You should never be in the situation where you can constrain something without paying the fair price for it,” she states.
She says DNOs use of both flexibility markets and flexible connections to manage network constraints is “splitting” apart the value of that flexibility in a way that doesn’t happen at the transmission level.
“If you look at the future of balancing, obviously there will still be lots of balancing that takes place between transmission-connected assets, whether that’s generation, storage or demand,” says Bragg. “But what we know is true is that there will also be an increasing contribution to balancing from the distribution side.”
She notes that a lot of new renewable generation and energy storage has, or will be, connected at the distribution level: “All of that, to me, paints a picture where you want all of that participating in national markets and you want as big flexibility markets as you possibly can at the distribution level so we can get as much flexibility as we can to help balance the system and we can exploit as much as the renewable electricity that we have on the system, regardless of voltage.”
Bragg says there are obviously physical and technical constraints which mean that users at the distribution and transmission levels cannot be treated exactly the same – “that’s totally fine” – but adds: “We can’t have slightly artificial barriers being put in place.”
She worries that Ofgem’s work to date has been storing up problems as we move to a system with much more flexibility at the distribution level.
Bragg says dynamic time-of-use DUoS charges could be helpful in providing a “crude, rough profile” for flexibility requirements, and in doing so, “work constructively with the more precise signals sent through flexibility markets.” But she says this also poses risks: “They need to be predictable enough that people can anticipate them when they are bidding into other markets to work properly.”
Thus far, Bragg says Ofgem has not really addressed the issue of network charging in a sufficiently holistic manner: “We were quite in favour of the access and forward looking charges review being quite ambitious on distribution and starting to get into these bigger questions about connection terms, about financially firm rights, and Ofgem backed away from that quite a few years ago as too ambitious, which is a bit disappointing.”
If the regulator is going to do this, Bragg says it also needs to re-examine the changes made to way distributed generation is treated with regards to transmission charges: “There has always been this really difficult questions about the benefits of having local generation… My view is Ofgem did a really poor job of properly qualifying those. The Embedded Export Tariff is not well researched.
“I think a proper review of the value of embedded generation within the context of bidirectional flows is one of the first things you need to do,” she concludes. “You can’t be just saying we should expose generation to charges all the way up to transmission because we just assume it exports out of the distribution zone because that’s not the case.
“It’s not the full picture.”