In an article first published in the January 2018 issue of New Power Report, Janet Wood looked at how locally electricity should be priced. Three years on, and given NGESO’s need to manage rising constraint costs, is it time to open the question?
Within Europe’s ‘single’ internal electricity market (IEM) there is not a single price across the whole continent. Instead, prices are set in specific zones. They can coincide with national boundaries, and in many cases they do. But the EU has long argued that this is inefficient. Instead, zones should apply to natural boundaries in the electricity system.
This already happens in some countries. Norway has five zones, Sweden three and Denmark two, for example. If there are bottlenecks in the transmission system, the zones may end up with different prices and as a result power will flow from the low-price area to the high-price area, over time also directing investment. The GB market sees power flow across interconnectors in this way as prices change.
GB is a single zone, although the capacity constraint at the England-Scotland border is exactly the type of bottleneck that the EU would like to address with zonal pricing, and some have suggested splitting the GB market into two price zones. That border constraint will be alleviated by the addition of the so-called ‘Western Bootstrap’, which saw its initial energisation in December and will allow a transfer of another 900MW between Scotland and the England/Wales system.
As similar investments are made they remove bottlenecks on the system. As a consequence, the EU requires zones to be re-examined on a regular basis and the next review is due in 2018.
On the node
Zones refer to large scale energy transfers. But locational pricing is seen as increasingly attractive at a much more ‘granular’ level in the system. At the extreme, that could mean revealing the cost at every ‘node’ – defined as any point on a circuit where two or more circuit elements meet. That could bring pricing down to street level, with areas where the system is overloaded priced more highly than those where it is not.
That has been excluded up to now, not least by the complexity of managing such a system and the cost of the computing power involved. But the cost and complexity of computing now present few barriers and it has revived interest in nodal pricing.
In a 2017 working paper on reform of electricity network access and forward-looking charges, Ofgem said it would not take forward either nodal or zonal charging at present; nodal charging would be “highly complex and has particularly unclear, unproven potential in its application at distribution level” – although it added that “this is a key area of the network where we think signals need to be better.” It also said new zones or nodal charging would involve major change to industry arrangements and existing contracts and could not be consistent with the current self-dispatch model.
But both EPRG and Helm gave a nod in that direction. The EPRG paper said: “the scope for nodal pricing of electricity has increased … given recent improvements in computing power and smart metering. A move towards more granular electricity prices will help improve location decisions fourth-generation investment, and enhance the value of greater system decentralisation.”
Professor Dieter Helm noted that his proposal for auctions of ‘equivalent firm power’, “deal with the intermittency in delivery capacity. They do not address the costs to networks of intermittency and location. This requires nodal pricing and here new smart technologies open up a much bigger prospect for considerable advance.”
He added, “The new ability to use smart meters, smart networks and, more generally, smart systems means that the pricing of networks and especially nodes can play a much bigger role.” Helm suggested that could apply in network reinforcement, where a regional system operator could employ auctions to pit network reinforcement against investment in generation, storage or demand-side measures.
Speaking to New Power this month, Electron’s Jo-jo Hubbard said that by using a blockchain platform with data on all the assets in a network, “you can have just one price for a whole region or you can have a price for a specific transformer. You can put in a bank of EV charging units and if you want to study the effect on the grid you just have a price for that area.”
That’s in the future.But it is not a theoretical question. The interconnected electricity markets in Pennsylvania, New Jersey and Maryland (together known as PJM), are jointly the largest US transmission system, serving 13 states (plus Washington DC) with 183GW of capacity. In that system, locational marginal prices are calculated at over 7000 nodes on an hourly basis.
In a recent interview with New Power, Erik Nygard, chief executive of Limejump, spoke in favour of moving to a more granular approach in GB.
His company aggregates demand response from business customers to meet system needs and he said of a move towards trading at the distribution level, “it means that you are possibly getting better nodal pricing through the system. You will have constant pull and push on the system at every location across the country. Getting granular is great for companies like us because we can aggregate companies in specific geographies and provide the service very quickly.”
But Nygard did not advocate pricing at every node, saying he was not sure how large a charging area should be.
Nigel Turvey from WPD set out similar concerns about making charging too granular. He said that concern had been raised when considering locational use of system charges on the distribution networks. “The moment you bring in nodal charges you need very little change on the network to have a big change in the charges,” he said, asking “what locational message are you really sending to people? The moment they connect, they change the nodal charge and suddenly the incentive they had to connect there is gone.”
Nordpool’s Richard Sarti echoed that concern. Nodal pricing has been proposed, but not pursued, in the company’s home market of Norway. Sarti said there were concerns over the uncertainty for system users. If a large electricity user connects to the system it has to consider the likely charges for 20 years into the future, he said. A granular locational charge would have an “inherent risk” that could not be hedged.