03 Nov 2022
Ed Porter

REMA: what’s the direction of travel for locational marginal pricing?

On 10th October, the REMA (Review of Electricity Markets) consultation closed. BEIS received just under 220 responses and will let us know the next steps this coming winter. One of the biggest changes suggested by REMA is the implementation of locational marginal pricing. But what does National Grid ESO think?

In the video below, Ed and Robyn discuss the implications that any transition to locational marginal pricing may have.

Ed and Robyn discuss REMA and locational marginal pricing.

(For more information on REMA, check out this explainer and our recent podcast on the topic.)

National Grid ESO has released a few important documents from its recent Autumn Forum. We’ve highlighted eight key points - focusing on National Grid ESO’s view of a move to locational marginal pricing. (Plus a bonus point at the end on Mandatory Frequency Response.)

Locational marginal pricing will encourage decarbonization

Key quote:

Implementation of nodal pricing with central dispatch creates an enduring foundation upon which to build a holistic market design for net zero. Without these in place, the wholesale market price is missing a key component: near real-time, dynamic, locational signals. This missing component will lead to both generation and demand side assets responding to inaccurate price signals, resulting in inefficient dispatch and an accelerating rise in costs; all of which will impede decarbonisation.

Our view:

This is a strong statement on the benefits of locational marginal pricing. In our view, it is clear this is a preferred option for National Grid ESO.

For an explanation of what we mean by ‘locational marginal pricing’, check out the video below.

Robyn and Alex discuss what locational marginal pricing means, and the potential pros and cons.

The industry will be getting sample/shadow nodal data

Key quote:

Ensuring that market participants have the necessary data and information during a transition phase to be able to model nodal prices would be key. In other markets this has been facilitated by publishing 'shadow' nodal prices before full implementation for participants to view and begin to model.

Our view:

The shadow data is going to be critical to building investor confidence in nodal pricing - we’ll be looking out for it!

Similar markets have been studied - but Ofgem’s technical assessment will be key

Key quote:

Ontario provides the most recent case study of moving to nodal pricing but has large amounts of hydro in its generation mix rather than intermittent renewables.

Sir Adam Beck I Generating Station in Niagara Falls, Ontario. (Image source)

Clearly, however, no international experience will map directly to GB and its transition to 2035, hence why the Ofgem technical assessment of LMP will be a key piece of evidence for this topic going forward.

The number of nodes in a nodal market is unclear

Key quote:

ESO's Phase 3 qualitative assessment did not require an assumption on the number of nodes that would exist in a GB nodal market. This is something that will be considered as part of Ofgem's technical assessment of nodal pricing.

Our view:

While locational pricing looks to be included, the number of and extent to which nodes are set on DNO networks is unclear.

You can check out our previous analysis of what potential nodes may look like here.

Possible nodes in an LMP framework could be the 14 grid supply point groups, or even more granular than this. Each node could have a different wholesale electricity price, as opposed to the current situation where there is one wholesale price across GB.

TNUoS charges may become a cost-recovery mechanism only - equal across all locations

Key quote:

We cannot at this stage definitively state how network charging might be reformed to coordinate with a GB nodal wholesale market, as this would have to be agreed in consultation with industry stakeholders. However, in moving locational signals into the wholesale price, we would not expect transmission charging locational differentials to be required to provide long-run locational signals. Transmission charging may therefore logically become a cost-recovery mechanism only, with equal charges across all locations.

The Energy Academy: How Transmission Network Use of System charges work

There is also an interesting side point with regard to network charges lobbying...

Key quote:

Our analysis of jurisdictions with nodal pricing found that hedging tools such as Financial Transmission Rights are successfully used to help market participants manage risk and that these would be an improvement on the long-term signals currently provided in the GB market via network charges which are subject to continuous regulatory risk where the outcomes can be vulnerable to lobbying by vested interests.

Zonal markets are sub-optimal compared with a fully nodal system - due to internal congestion costs

Key quote:

Our analysis found that market splitting (zonal markets) could temporarily alleviate some constraints and provide improved market signals from the status quo; however, intra-zonal congestion costs would remain, and as generation evolves and new transmission comes online, it is inevitable that rezoning would be required to retain these new efficiencies.

A nodal market would allow Distribution System Operators to better optimize their network

Key quote:

The introduction of a nodal market can be expected to provide more accurate signals for DSO/DNO to optimise their network and efficiently procure flexible services. DNO/DSO currently do not have upfront visibility of the market conditions that impact their local networks and therefore are often not in a position to optimise their network fully.

The Energy Academy: What Distribution Network Operators do (and how they’re evolving)

Generators with CfDs are likely to be protected in any transition to locational marginal pricing

Key quote:

The need for investment in low carbon resources for Net Zero is immense, and to date driven by low carbon support policy, particularly CfDs. Existing CfD generators are likely to be protected.

Our view:

Both nodal and national pricing are viable schemes, but the transition from one to the other is going to be a bumpy ride!

Bonus: Mandatory Frequency Response will (eventually) be replaced by a move to real-time procurement

Key quote:

MFR volumes won’t be offset by the new DM and DR products, although we do expect DC/DM/DR to be eventually procured intraday, and that move to real-time procurement would replace MFR.

Our view:

Modo notes that change would seem to be creating a level playing field for frequency response services - and it is therefore a step in the right direction!

Neil and Quentin discuss Mandatory Frequency Response.

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