As GB transitions to a low carbon electricity system, new renewable generation is tending to locate further away from demand. The reason for this is simple, the windiest areas tend to be on higher ground away from centres of population (to take just one technology as an example). This puts extra strain on the electricity network, resulting in "constraints" – when parts of the network are at capacity and cannot transport any more energy. This results in the electricity system operator (ESO) having to tell some generators to turn their output down ("curtailment"), and be compensated for doing so, and others to turn theirs up, all at short notice through the Balancing Mechanism.

Having different prices in different areas should make the electricity system more efficient and minimise the costs of running it. Locational pricing would send operational signals (when to dispatch) as well as locational investment signals (where to site an asset).

Locational pricing is the only option being considered in REMA that influences how a generating asset operates as well as where it is sited. The wholesale electricity price will change to reflect the current local conditions of supply, demand, and network capacity. This will encourage the market to react to changes in these areas. Electricity generators will therefore only provide power when the market needs it and when there is enough network capacity to handle it, which will help to reduce costs. Customers are likewise encouraged to use electricity when it is cheaper and more readily available, which can help lower their bills.

According to DESNZ's modelling, locational pricing could help reduce system costs by £5-15 billion over the period 2030-2050.

Lower consumer bills: With national pricing, the cost of wholesale electricity is determined by the most expensive power plant needed to meet demand, which is typically a gas-fired generator. This can result in extra profits for cheaper renewably powered plants, which can potentially increase costs for consumers. However, as more renewable plants obtain price support under the CfD, this effect is expected to lessen.

On the other hand, locational pricing in the form of zonal pricing sets the cost of electricity based on the most expensive power plant within the specific zone. This can lower the extra profits made by cheaper power plants in that zone. The money saved from these reduced profits eventually goes back to the consumers, helping to lower their electricity bills.

Interconnectors: Under the current national pricing, interconnectors do not always operate effectively, in fact, at times they can do the opposite of what the GB electricity system needs. For example, energy may be being exported to the Continent from the South of England where in fact more generation is needed, and it may be being imported into Scotland where energy cannot be transported to the rest of GB due to network constraints. Having more effective locational operational signals could mean interconnector flows better reflect the needs of the GB system. This could improve system efficiency and lower overall system costs.

Demand side flexibility: Locational pricing could make investment in demand side technologies more attractive by passing through the benefits of potentially significantly cheaper electricity in over-supplied parts of the country. This could incentivise investment in different types of storage and hydrogen electrolysers, which can easily be sited anywhere. Energy intensive industries, or end users who can shift their electricity demand to match renewable output, may look to invest in new or expanded facilities in regions that have high levels of renewable generation (the Humber, say), and therefore lower prices, creating new jobs and opportunities for the local economy and driving economic growth. It could also potentially result in more people using electric heat pumps and electric vehicles in areas where the wholesale price is lower. REMA could therefore indirectly support other key elements of the Government's net zero platform – i.e. the hydrogen economy and greater use of heat pumps in home heating.

Demand side response: locational pricing could encourage more demand-side response by encouraging a range of end users - from homeowners optimising heat pump operations and EV charging, to large industrial facilities adjusting their production profiles - to align their electricity usage with the amount of electricity being generated in their area at any given time. (Of course, there are limitations to this – homeowners will remain more likely to use electricity on winter evenings, for example.)

DESNZ recognise that locational pricing would significantly change the current risk allocation. The benefits (better operational and investment signals) need to outweigh the extra risks on investment decisions and financing costs. From our engagement with the industry webinars that DESNZ have been running, it is clear that the industry is generally nervous of locational pricing, and investors are holding off investing in projects until a decision has been made one way or the other.

Locational pricing would increase the following risks for investors:

• Price risk – generators risk making less revenue under locational pricing than they would do under national pricing (e.g. if their zone has consistently lower wholesale revenues), or revenues are less predictable (due to changes on local supply and demand). This is a particular risk if developers of new generation projects cannot simply move their project to a different area to take advantage of better prices – e.g. wind farm generators, who need high ground.
• Volume risk – the risk that generators are not dispatched as often so their revenues are lower and less predictable.
  These are likely to increase the cost of capital for new projects, which could end up being passed back to consumers in the form of increased financing costs.

However these risks may have a greater impact on existing generation projects. Unless generators have a CfD which will act to keep their revenues stable through the strike price mechanism (see our previous REMA insight for discussion on this point), existing generators could be exposed to significant changes in market prices, with no ability to relocate or substantially mitigate this risk. This may impact both revenue and financing costs for such projects.

Such a fundamental market change is likely to constitute a "change in law" under long-term offtake contracts and will likely lead to many long and painful renegotiations for existing projects.

DESNZ are also working on four alternative options to locational pricing, which generally build on existing arrangements and carry less risk for investors, although some could still mean significant reforms:

• Option A: Using Ofgem's pre-existing TNUoS and DUoS network charging reform programme
• Option B: Reviewing Ofgem’s transmission network access arrangements – this could result in existing access rights being changed and all transmission access rights becoming non-firm (which means generators are not compensated if the grid cannot accommodate their power). This will only happen if locational pricing or central dispatch is introduced.
• Option C: Expanding measures for constraint management, including expanded local constraints markets, improved congestion forecasting, and storage-based solutions – all these could be potential new revenue streams for investors and generators, and some could be applied alongside locational pricing.
• Option D: Optimising the use of cross-border interconnectors – building on work already underway within DESNZ, ESO and Ofgem. Potential options include improving redispatch and SO-to-SO trading; and exchanging balancing products between the EU and the UK.

We do not have space in this Insight to go into more detail on these reforms, several of which are being taken forward by Ofgem/ESO in parallel to REMA, but if you would like to know more, please contact us.

These reforms are likely to influence where to site new generation and demand, but they will not significantly influence the real-time operation of the electricity market, so the consumer benefits are likely to be more limited than locational pricing. But they are more palatable to investors.

Other options DESNZ are considering for making the electricity system work better include:

• Improving temporal signals – shorter settlement periods of 5 or 15 minutes, with the aim that this would encourage greater market participation by smaller assets, moving costs out of the balancing mechanism into the wholesale market.
• Balancing Mechanism reform
• Centralised dispatch – either alongside locational pricing or as a standalone option
• Aligning longer term ancillary services with CfD and CM auction – to provide more revenue visibility and inform investment planning.