A wholesale market based on ‘locational marginal pricing’ (LMP) has long been advocated by a number of electricity sector economists and commentators as ‘the right answer’, but what is the question, and is it the right answer for the challenges we face now in decarbonising and expanding the electricity system in Britain?
In this extended blog, Simon Gill, Callum MacIver and Keith Bell outline what LMP is, why it’s now being recommended by a number of significant players but, equally, why it’s being questioned by others.
Trading electrical energy and operating the power system
Delivering on the UK Government commitment to a net zero power system in 2035 will mean large scale, radical change to the system, change that needs to be delivered in just 13 years. It is a central part of our wider ambition for a net zero economy by 2050 and isn’t just about decarbonising the production of electricity but also meeting the 50% to 80% of energy demand that could be served via electricity in the future.
Wind and solar will play a key part in net zero power, potentially producing up to 80% of all our electricity but their characteristics – variability, uncertainty and the fact that they generate electricity at zero marginal cost – mean that we have to think carefully about how to plan and operate a power system around them and organise our electricity markets.
Today we have a relatively decentralised system of wholesale trading and self-dispatch where electricity producers strike deals through bilateral forward contracts, Power Purchase Agreements, or trade on independent power exchanges then notify the system operator of their intention to generate. It’s only when we reach the last hour before delivery that centralised arrangements take over with National Grid Electricity System Operator (NGESO) operating the Balancing Mechanism to ensure the system is balanced, transmission network limits are respected and ‘credible’ disturbances can be survived.
Several organisations are now proposing a move to a very different form of wholesale market based around Locational Marginal Pricing (LMP), where a centrally dispatched, day-ahead ‘gross pool’ and real-time adjustment markets replace the existing self-dispatch model. LMP has been advocated for introduction in Britain by numerous economists for many years. NGESO, the Energy Systems Catapult and others are now arguing that it will incentivise the offering of ‘flexibility’ from demand, storage and generation to complement the variability of renewables and deliver more efficient use of the transmission network by providing strong locational price signals. These, it is contended, will drive economically efficient decisions on where to invest in new facilities and how to operate all resources including generators and interconnectors.
What is locational marginal pricing?
LMP has existed for decades in other parts of the world. It is particularly common in North America where markets in California, Texas and the North East of the country are based around locational marginal pricing at the level of either zones or each node of the transmission network. The fundamental principle of LMP is that the price that is paid by demand and received by generation reflects the marginal cost of electricity at that specific location. That price will vary across the network for two main reasons. Firstly, network limits mean that additional output from cheap generators cannot always be always used due to the need to keep network flows within physical limits, i.e. the network in key locations is congested; and secondly because total electrical losses on the network will vary depending on where power is injected or withdrawn.
For example, if you are in Scotland and there is an excess of wind power relative to demand in Scotland and the network’s ability to export power to England, some of that available wind power would need to be curtailed and the marginal cost of meeting additional local demand will be close to zero: an extra unit of electricity demand there could be served simply by releasing a unit of curtailed wind. By contrast, an extra unit of demand in England would require an extra unit of output from somewhere in England or Wales, most likely a gas-fired power station, the cost of which has exceeded £200 per MWh during periods in 2022.
In Britain’s present day decentralised trading arrangements, it’s quite difficult to say what ‘the wholesale price’ of electricity is. There are different prices depending on how far ahead of time a trade is done, and where the trade is done, e.g. through a power exchange or the Balancing Mechanism (BM). This differs from an LMP market where, although decentralised trading can still happen, there is a requirement that all power is channelled through day ahead and real time LMP spot markets. In addition to the locational price signals, this involves a number of other market design changes:
- Central dispatch: LMP markets operate using centrally managed optimisation tools to determine ‘cost optimal’ (within the limits of the algorithms used) dispatch of generator outputs and settings of flexible demand and storage based on bids and offers submitted by all market participants.
- Non-firm access rights: Unlike in current GB arrangements, generators and flexibility providers in LMP-based markets do not receive firm rights to access the system. Rather, instead of having the right to compensation when lack of network capacity intervenes, the right to inject or withdraw power is granted temporarily only when participants are dispatched ‘on’ by the central algorithm either in the day-ahead or real time market.
- A requirement to participate in central dispatch: Although there are options to opt-out of economic bidding and ‘self-schedule’, it is mandatory for all participants above a certain size to participate in the central dispatch and to receive or pay the LMP clearing price for their
- Day ahead dispatch is financially firm: If dispatched ‘on’ in the day-ahead LMP market the financial commitment is firm. However, participants can buy their way out of that obligation in the real-time market which typically closes around one hour before delivery.
- Financial tools for hedging risk: In most LMP-based markets around the world these include Financial Transmission Rights (FTRs) which pay out the difference in price between two nodes if there is congestion between them, and virtual trading which provides a route to hedge any difference in prices between the day ahead and real time market.
Why is LMP being considered for GB?
The case for charation of location in terms of value provided to the electricity system, and efficient utilisation of resources. We consider each of these in turn.
Constraint costs
The removal of financially firm access rights from generators means that curtailment costs (the need to compensate generators whose contracted power can’t be used due to system balancing or transmission constraints) would no longer be a feature of the market. As NGESO states in its Market Reform work, “the cost of these ‘constrained-off’ payments is one component of balancing costs and is ultimately paid for by consumers via [Balancing Service Use of System (BSUoS) charges]. Under nodal pricing, constrained-off costs are removed since assets whose output would cause constraints are not dispatched”[1].
To read the rest of this blog please continue to the UKERC website.