REMA unpacked: Do market reforms go far enough?

By David Blackman

27th March 2024

Industry bigwigs gathered last week at the first birthday party for the Department for Energy Security and Net Zero (DESNZ).

Officials and ministers had something else to celebrate – the long-delayed publication of the second stage of consultation into the government’s Review of Electricity Market Arrangements (REMA).

Josh Buckland, a former Downing Street special adviser on energy and climate change, emphasises the number of options that have been discounted from the initial REMA consultation document published nearly two years ago. “They’ve really narrowed the field quite significantly,” he says,

One of the big calls was on whether the wholesale market should be split in two to reduce the influence of gas on electricity prices. This was flavour of the month among sector academics and politicians at the height of 2022’s energy price crisis but brutally dispatched in last week’s document.

Contracts for Difference (CfDs), which provide an increasingly large share of the UK’s electricity but are not governed by the wholesale market’s marginal pricing arrangements, are already delivering many of the benefits of cheaper renewable power, DESNZ concluded.

It has decided that retaining the existing wholesale market structure will enable these benefits in terms of cheaper green power to be delivered via CfDs without the need for a lengthy overhaul that could put off investors from UK electricity generation.

The decision on splitting the wholesale market reflects the “steady as she goes” flavour of the latest stage of REMA.

Tom Smout, senior research associate for the British power market at consultancy Aurora Energy, says: “They’ve mostly opted for boring, iterative improvements over radical, potentially destabilising, reform options. They’ve mostly gone for the safe options.”

Eyes on the compromise

This focus on incremental rather than big bang reform is reflected in the decision to rule out replacing existing national wholesale market prices with nodal local marginal pricing (LMP) arrangements.

Instead the paper plumps for two less radical options. The first is zonal pricing, a less granular version of LMP, which would see Great Britain’s wholesale market broken up into a series of zones that would be more regional in nature than the hyper-local nodes.

The second is what DESNZ calls a “business as usual plus” option, which would retain a single national wholesale price but with more emphasis on providing locational demand signals through network tariffs, such as through improvements to the TNUoS (Transmission Network Use of System) regime.

“It is mostly a gradual evolution of existing mechanisms, which is sensible,” says Buckland.

Smout says zonal pricing is “a compromise option but one that commands widespread support by a lot of parties”.

Enthusiasts for LMP, such as the Energy Systems Catapult and Octopus Energy, have rallied around the zonal flag, Buckland says: “The proponents of locational pricing who were largely supportive of nodal pricing now seem to have shifted to a position where they now support zonal pricing.”

Meanwhile, the biggest critics of LMP, including established generators, appear to find zonal pricing more palatable.

Tom Glover, UK country chair of RWE, tells Utility Week: “Our very initial view is probably still that the risks outweigh the benefits but it’s a lot less risky than nodal.

“We’re not yet convinced there is a good enough business case for zonal but it’s a much less risky system for investors and much simpler to implement.”

This is partly because averaging out prices over a zone leaves investors “not so exposed” to the risk of a new generation asset being built next door to their own plant with the knock-on implications for local pricing levels, he says.

Another plus point for zonal versus nodal pricing is that bigger geographical units create conditions for greater liquidity of investment than smaller nodes.

Glover says generators like RWE have got used to modelling the variations in prices between the TNUoS (Transmission Network Use of System) regime’s different geographical zones for the past couple of decades.

But the “very clear zonal signal for siting assets” offered by TNUoS is also an argument for refining this system, one of the options that the government has proposed. “If we get TNUoS reform right, the locational siting signal is there”, Glover says.

Gemma Grimes, director of policy and delivery at Solar Energy UK, agrees that the government’s Plan B to reform the existing regime is the best option.

“Other changes could address much of the problem without such a serious intervention,” she says, such as accelerating grid deployment alongside reforms to TNUoS.

Before proceeding with the next stage of wholesale market reform, analysis should be carried out into how the costs and benefits of zonal pricing compare to a “fully optimised” version of the existing network tariff regime rather than how they stack up compared to the status quo, Glover says: “If you haven’t optimised the current market, then you haven’t really done a fair comparison if there is a business case (for zoning).”

Smout agrees. “We compare it to the status quo scenario but the existing system could also be improved.”

‘Zonal pricing doesn’t need to take five years’

Rachel Fletcher, director of regulation and economics at Octopus, tells Utility Week that “radical reform” is still necessary to make “best use” of flexible assets like grid-scale batteries, electric vehicles, and interconnectors.

And reforming the wholesale market by introducing zonal electricity pricing could be carried out sooner than the five years that the government has said it would take, she argues.

“There is no reason why it needs to take that long,” Fletcher says, adding that she suspects a “big part” of the government’s suggested timetable will be accounted for by policy making.

“You can decide where you’re going quite quickly and curtail that time,” she says, pointing to the accelerated roll out of the Covid-19 vaccines as an example of how much quicker governments can operate if they have to.

“We should be using the same approach with zonal,” she says adding that the government should swiftly rule out exploring incremental reforms of the existing wholesale market, such as network charging.

She also says that software used to run zonal pricing systems in other parts of the world could be bought and trialled on a shadow basis while finalising the policy design in parallel. She says this is another parallel to how vaccines were developed during the pandemic.

But Ana Musat, executive director for policy and engagement at RenewableUK, says introducing zonal pricing would take longer than the government thinks, based on experience abroad.

She believes seven years is a more realistic timetable for implementing this reform, pointing to examples in Australia, Canada and Texas.

Some disruption to the market is inevitable given the seismic shifts in demand and supply for electricity that the grid will have to cope with over the next decade, says Fletcher: “It’s very difficult to see how you address the current problems in the system without upsetting the applecart for investors.”

She also believes concerns about potential disruption to the market from zonal pricing ignore the logistical challenges involved in delivering the amount of transmission infrastructure required to serve an unreformed national wholesale market.

“Understandably, people raise eyebrows at how long it will take to implement a new wholesale market but not enough attention is being given to the almost physical impossibility of building the transmission network we need if we don’t have the right price signals that help us optimise the assets on the system,” Fletcher warns.

“This really needs serious attention, because there’s a risk that we’re all worrying about how long it takes to reform the wholesale market. Meanwhile, we’re way behind on our transmission investment. The international supply chains for electricity networks are strained. There’s limited capital and expertise and there’s limited public appetite for pylons up and down the countryside.”

Pointing to estimates that an eightfold increase in transmission network build out is required to transport the greater volume of electricity that will be required to meet the UK’s 2035 grid decarbonisation target, she says: “If you look at what transmission has been built in 2022 and 2023, we’re already way behind in the transmission build that you need to get to 2035.”

But Musat says there is a risk that zonal pricing could be seen as a “silver bullet” for tackling issues around the transmission network build out, which “distracts from the other bits of reform that needs to happen anyway”.

Introduction of zonal power pricing could push 10GW of additional offshore wind to locate in southern England by 2050, according to research carried out by consultancy LCP Delta and Grant Thornton for the latest REMA consultation.

However, the ability of zonal pricing to push generation assets closer to centres demand remains limited by grid and planning constraints, Musat says: “Even if you incentivise through zonal pricing, you’re still basically banned from building onshore wind.”

Smout agrees. “If you’re not actually able to get planning and a grid connection, it doesn’t matter what the price signal is.”

Moving the dial for large energy users

More localised pricing could though encourage large energy users, like data centres, to relocate where power is cheap, says Fletcher: “Even if you think there’s very little chance of zonal pricing having an impact on the siting decisions of renewables, it will almost certainly have an impact on the siting decisions and the investment of large industrial users.”

But given that power costs are just one of the criteria that even energy intensive industries weigh up when making location decisions, Smout is sceptical.

“There’s also potential in the longer term for things like hydrogen generation or data centres to move to lower price areas but you’re not really going to entice the commuters around London to move.”

These calculations could though start to shift if a new Labour government is elected with a less restrictive approach to planning onshore wind farms, says Smout: “If we get locational pricing and they lift the ban on onshore wind in England, which Labour government has talked about, that could lead to quite a different set of outcomes.”

The timetable outlined in the REMA consultation, which points to a conclusion of the process next year, suggests that these final decisions will be taken after the next general election, says Buckland, who is now a partner at Flint Global.

Adam Berman, deputy director of Energy UK, says that while the intellectual arguments for zonal pricing are “fairly sound”, they will be a hard sell politically if they end up resulting in customers paying different energy bills depending on which zone they live in.

Given the other energy priorities that an incoming government will face, such as contentious grid connection and planning reforms, he struggles to see it wanting to spend much time and political capital on market reform.

“That (zonal pricing) may well have benefits but an evolutionary programme of change may not get you all the way but it will probably get you most.”

Adam Bell, head of policy at consultancy Stonehaven, believes it may make sense not to introduce zonal pricing now but take a fresh look at the issue post-2035 when much of the infrastructure to deliver the government’s target of a net zero emissions grid should hopefully have been delivered.

“That sounds like a fair way of approaching this problem. It still sorts some problems quite nicely but stops you from losing out on all the investment you require in the short run.”

If DESNZ celebrates a 10th anniversary party, this suggests that zonal pricing could still be a talking point.

*Additional reporting by Tom Grimwood

This article first appeared in Utility Week’s Digital Weekly edition. To read the issue in full, click here.