Renewable developer sounds alarm over network charging reforms

Octopus Renewables has raised concerns over Ofgem’s ongoing review of forward-looking network charges and the regulator’s apparent desire to expose more distributed generators to transmission fees.

Investment director David Bird said ending the exemption for embedded generators would jeopardise the viability of onshore wind projects in Scotland and the north of England and slow progress towards reaching net zero emissions.

Ofgem is currently conducting a significant code review looking at forward-looking charges and network access arrangements after concluding a similar review of residual charges – referred to as the Targeted Charging Review (TCR) – in November 2019.

Forward-looking charges are intended to provide price signals to network users, reflecting their impact on future investment depending on where they are connected, whilst residual charges are designed to recover the remaining sunk costs.

Speaking to Utility Week, Bird said the review of residual charging “was almost dealing the leftovers first and now they’re getting to the bits of network charging that they want to send signals to the market. They’re trying to find a way of using network charging to incentivise people to generate and consume power at the right times and in the right places so as to reduce the overall cost of the system, which is an effort that makes sense.”

“One of the things they’re looking at is should distribution-connected assets more widely pay transmission network costs,” he added. “And I think the rationale for that is all the same arguments they made as part of the TCR, which is about removing distortions.

“If there are distortions in the marketplace where different kinds of generators face different charges, then maybe the wrong kind of generation gets built or gets called on to operate and that might increase costs to consumers overall”.

Bird continued: “If they made that change, which is one of the changes they’ve flagged as something foremost in their thinking without quite getting as far as a minded-to decision, then effectively every single generator bigger than 1MW would have to pay transmission network charges.” At the moment, distributed generators are only liable if they have a capacity of more than 100MW.

He said: “If you’re on the distribution network, you’d also have to pay distribution charges or maybe get a credit if you’re in a particular place, whereas if you’re a generator connected to the transmission network clearly you have to pay transmission network charges but you don’t have to pay anything for distribution costs. I suppose they’re removing one distortion but leaving another in place if they do that.”

Transmission network charges vary significantly across the country. According to National Grid Electricity System Operator, a notional intermittent renewable generator with a load factor of 40 per cent could expect to pay charges of around £24.68/kW in Argyll in 2020/21, whilst a similar generator in the Cotswolds could expect to receive a credit of roughly £11.57/kW.

These figures, representing the highest and lowest indicative rates for such a generator, include the residual transmission credit, which was due to be removed at the beginning of April as part of Ofgem’s wider decision to shift residual charges entirely onto final demand. However, earlier this week SSE requested an appeal against the change with the Competition and Markets Authority.

Distributed generators with a capacity of less than 100MW can currently receive an Embedded Export Tariff by outputting power during the three half-hour periods of highest demand each winter known as the triads. This explicit credit replaced the triad avoidance payments they were previously able to earn by enabling suppliers to reduce their transmission charges. It also varies across the country, with generators in London receiving £10.94/kW in 2020/21 but those in Scotland, Yorkshire, the North West and Northern England receiving nothing at all. The residual component of the tariff is being gradually phased out.

Bird explained that “it’s relatively cheaper from a transmission cost point of view to build and operate generation further south because the way these costs are set is in reference to average demand and the average demand is located very much in the south of the country.

“So effectively if you’re generating in Scotland your power has to travel through many more miles of wires to find a home on average and so you pay a higher share of network costs.” He said exposing embedded generators to these price signals would be “overwhelming” for those in Scotland and the north of England.

Net zero

“There may also be some winners,” he acknowledged. “It may make the business case for, for example, solar in the south of England better.”

“But”, he added, “if you look at where some of the lower hanging fruit is in terms of the next few gigawatts of generation we need to build as part of net zero, particularly in the onshore context, it’s wind in Scotland, and so what these changes would do is make it much less economically viable to build distribution-connected wind in Scotland.

“Renewable UK did some work on this earlier last year that suggested that around 2GW of new planned onshore wind capacity in Scotland would effectively go missing if these changes happened and it’s far from clear how that capacity gets replaced given the planning environment around wind outside of Scotland.”

Bird said Ofgem has suggested it may apply some kind of phasing to help mitigate this impact but warned “this only goes so far”. He said existing generators would be unable to respond to the price signals as “you can’t pick up a windfarm or solar farm and move it”, adding that: “Ofgem hates grandfathering and have been pretty clear that grandfathering is unlikely because they see impacts on repowering decisions and things like that.

“I think a recognition that imposing these charges on existing generation doesn’t actually help anything – it is just shifting value around the marketplace arbitrarily – would be helpful but it doesn’t do anything to alleviate the concern over the journey to net zero side of things.

“There’s perhaps wider questions whether it’s realistic to expect all of the generation to be built close to where the demand is given the different wind resources in different parts of the country, given the different use of lands and the different attitudes and appetites for more wind turbines in particular, which are quite an emotive subject for some people.”

Price signals

Bird questioned whether transmission charges are even the right way to send these signals, describing them as “pretty crude and blunt”. He cited several recent Connection and Use of System Code (CUSC) modifications as evidence.

CMP353 will “stabilise” the expansion constant – a multiplier in the calculation of forward-looking charges that represents the annuitized cost of building new 400kV overhead power lines – at its current level plus inflation for the RIIO2 price controls. It was approved by Ofgem at the beginning of December.

Bird said the expansion constant would have “almost doubled” without the change and so the regulator passed an “emergency” modification to “hold it where it is until they’ve figured out what to do.” He said part of the reason for this issue was that “the calculation effectively isn’t fit for purpose because it’s based on the assumption that you build certain kinds of wires and they’ve built so few new wires in the last relevant period that it’s just not representative anymore”.

He also drew attention to the CUSC modification CMP325, a version of which Ofgem approved in November to hold the number of transmission charging zones at 27. National Grid Electricity System Operator otherwise expected the methodology for setting the zones to lead to an increase to 48, although Ofgem disputed this figure.

Bird said some industry figures believe a better answer to the issue would be “more locational wholesale market pricing, for example”.

On the other hand, he said more sweeping reforms would take a long time to implement: “That is not a quick exercise to resolve all of that and one of our biggest concerns as a business is the uncertainty and actually to have any chance of doing what we need to do in terms of funding the rollout of new generation you need to avoid investment uncertainty and situations where investors are losing out because they expect one set of rules to continue and then find the rug pulled from under their feet.

“There are conflicting worries there around uncertainty versus taking the time find a better way to send those locational prices signals.”

Low-carbon auctions

Furthermore, he cautioned: “It’s not clear that the market is fully on top of these changes and pricing this in”. He said this may be a particular problem for the next Contracts for Difference (CfD) auction which is due to take place later this year: “We’re expecting a decent sized pot in pot 1 that would allow onshore renewables to participate and at the moment I’m not clear how anyone bidding into that auction or any investors trying to fund the buildout of those developments is going to price this.

“Some people will potentially just be ignorant to it and you’ll have projects that could win contracts and then find themselves a year down the line realising they’ve bid at an uneconomic value…

“If government wants the next CfD round to be effective and many more rounds after that to get the tens and tens of gigawatts of new capacity that we need, there needs to be care taken now to make sure that issues like this don’t spook the investment market.”

When asked by Utility Week how he would resolve the problem, Bird responded: “I’m not expecting Ofgem to just drop this and I don’t think it’s right for them to drop this. The area definitely needs looking at. Honestly, I don’t think we have a clear picture as to what is the right answer and how exactly it should be looked at.

“I do think that it doesn’t make sense to make distribution-connected generators pay for the whole journey from generation to consumer but not have the same approach for transmission-connected – that does seem odd.”

At the same time, he said applying distribution charges to transmission-connected generators would also be challenging: “How do you identify which customer you’re going to or which set of networks charges you should be paying?

“It would need to be some kind of blended average and when things are blended averages Ofgem’s approach is they’d rather just see them lumped onto consumer bills as a fixed charge and actually one of criticisms some have had – and certainly my colleagues on the supply business – around the TCR changes putting the residual as a fixed charge on electricity bills is it really makes it much harder to incentivise flexibility because it’s just not moving the needle as much if you reduce your consumption in particular price periods because you’ve got this really big fixed charge whatever you do.”

“None of this easy,” he conceded. “I do think that the way Ofgem tends to model these things and look at the impacts has consistently missed over the last couple of reviews the reality of what can get built where. I just don’t think it’s realistic to send price signals that will be priced on the assumption that a load of wind will get built in the home counties to replace what you need in Scotland.”

He continued: “There’s a process point there around recognising that to hit net zero we need to build generation where it can actually be built, even if that’s more expensive than the idealised world of building it all right next to demand…They don’t quite have the modelling sophistication to deal with some of these subtler points”.

Coordination with government

Bird said his concerns would be somewhat alleviated if rising transmission charges in Scotland were reflected in CfD budgets but added: “I’m not sure the potential impacts of this thing are widely enough understood or accepted that it can flow into the budget allocation.”

He said: “If the big picture objective is to achieve decarbonisation at the lowest cost possible what it needs is that whole-system thinking, which again needs BEIS and Ofgem cooperation and there’s positive noise on that.”

Ofgem revealed in November that its minded-to decision on forward-looking charges, which had previously been scheduled for release in late autumn, had been postponed until 2021. In the energy white paper issued the following month, the government also announced plans to publish a follow up to the smart systems and flexibility plan released by the Department for Business, Energy and Industrial Strategy and Ofgem in 2017.

Bird said: “Until that announcement over the Christmas period, it felt like the access and forward-looking charges review was just carrying on and Ofgem were very much saying: ‘We’ll just do what we’ll do and if government wants to adjust budgets to meet its objectives then that’s their problem. And if you speak to government, they’ll say: ‘Network charging is for the independent regulator and we won’t interfere because we can’t under EU law.’

“I don’t whether any of that’s changed in a post-EU world. For all the positive noise recently, we haven’t seen any tangible evidence of that feedback loop working.”