Exploring the implications of locational marginal pricing of electricity

04 Oct 2022

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].

Whilst nominally true that the removal of ‘constrained-off’ payments would reduce system balancing costs, it is worth asking whether this simply raises other elements of cost and how much of the saving would finally reach consumers.

Previous investments by generators have been made under the assumption of firm financial access to the system which means that investors are not exposed to the costs and risks that network investment fails to keep up with generation connection. Moreover, investment in renewables involves sinking the vast majority of the lifetime project costs before operation even begins and recouping that investment over timescales of more than a decade. Today, projects can have relatively high confidence in the level of revenue they receive. However, if firm access is removed, their ability to generate revenue is reduced (during periods when they cannot get dispatched) and is significantly more uncertain (due to the difficulty in forecasting the level of dispatch and the price they will receive over the lifetime of the project). An open question is whether this would reallocate costs to other periods as well as raising the cost-of-capital for investment.

Where similar changes to access rights have been made as part of market reform in other jurisdictions, for example in the US, experience suggests that the transition to LMP markets has been accompanied by the need to reimburse generators for the loss of rights. This might be achieved through, for example, ‘grandfathered Financial Transmission Rights’[2]. To date, this has been done in the context of traditional schedulable power stations. However, there may be significant issues when replicating this with a large fleet of renewable generators with low short-run marginal costs. Much of the success of a move to LMP in reducing costs to consumers would seem to depend on the allocation, costs and benefits of FTRs or any other compensatory arrangement that might be introduced, about which there has been little discussion to date.

Locational signals to drive investment

The Energy Systems Catapult concluded in its October 2021 report into nodal pricing in GB that “over time this [an LMP market] is likely to lead to more efficient location of new resources and efficient expansion of the network”[3]. These resources include generation, interconnectors, flexible technologies such as energy storage, and some elements of demand such as energy intensive industries that have the scope to make a rational investment decision based on location.

One of the challenges of location-based pricing is in ensuring that it doesn’t inhibit the achievement of wider objectives. The three net-zero compliant scenarios from NGESO’s 2022 edition of their Future Energy Scenarios (FES) suggest that, by 2035, GB needs at least 100 GW of connected wind capacity. The wind industry has become adept at identifying viable locations for investment in renewables based on locational factors other than price such as the availability of resources, the likely ease of gaining planning consents and the ability to get a grid connection. Evidence from existing LMP markets suggests these signals often remain the strongest determining factors for investment.

It is clear that the abundant wind resource, availability of land and seabed, and favourable planning support in Scotland have provided stronger locational signals for investment there compared with many other areas of the UK. However, a lag in delivery of complementary transmission capacity for export suggests that nodal prices in Scotland under an LMP system would be zero or even negative for much of a year, providing a deterrent to investment. The availability or not of viable alternative locations for wind or other net zero compatible technologies would determine whether locational pricing drives optimal investment or, based on an assumption of a fixed amount of transmission network capacity, simply deters necessary investment.

NGESO, responsible for defining the strategic direction of electricity transmission development, has indicated that £54 billion of investment in Britain’s network infrastructure should be carried out in its ‘Pathway to 2030[4]. If it and further developments can be delivered in time, risks to achievement of 2030 renewable generation targets and net zero electricity in 2035 would be much reduced. However, such success in developing the network is far from guaranteed given the need for planning permission and early engagement of the supply chain.

Locational and time-varying signals to drive efficient dispatch

Once generation, demand, interconnectors and storage have chosen their locations and are operating, LMPs can provide a strong signal on when to be available and the central dispatch algorithm can schedule resources in a way that is close to the lowest cost combination. NGESO lay this out in their Market Reform work: “By embedding the locational value of an action in the wholesale price, nodal pricing enables market participants to optimally dispatch supply or demand in the right location and at the right time”.

This seems the clearest area of value that a move to an LMP market could deliver as it could potentially encourage more efficient use of existing assets given their availability and the network’s capacity. The challenge for opponents of locational pricing is to articulate alternative measures that could otherwise address the need for locational signals to enable optimal operation of the future system and drive future availability of resources. Whilst current arrangements might provide signals to development of, for example, battery storage or electrolysis, are they sufficiently strong to steer them towards locations that complement network capacity such as where curtailment of wind might be reduced? On the other hand, how easy would it be for anyone to forecast LMPs ahead of investment decisions, what would that do to risk and cost of capital, which parties are best placed to manage that risk and to what extent can or should risk be shared?

What next?

There is general agreement that current electricity wholesale market arrangements in Britain need to be developed to resolve the trilemma of low total cost of energy, secure supply, and net zero greenhouse gas emissions. The Department of Business, Energy and Industrial Strategy (BEIS) has invited views to inform its thinking on reform of market arrangements. However, satisfaction of the trilemma depends on much more than just the wholesale electricity market.

The cost of electricity is currently strongly linked to the cost of gas. In future, the electricity system will be much more strongly coupled than it is today to demand for energy for heat and for transport. Whilst there is general agreement that much of that demand will be electrified, the rate of progress is currently uncertain and there is considerable debate around whether use of hydrogen will extend much beyond industry and what form storage of energy – in Britain or elsewhere – will take to enable demand to be met during wind droughts lasting many days. Then, although the general direction of travel in respect of renewable generation capacity is clear – we need a lot more of it – there remains some uncertainty as to the ease of gaining onshore planning permission and the extent to which floating wind makes many more offshore locations economically viable.

At present, we lack a clear view on how different generation and demand side resources are likely to be spread, making it impossible to plan and develop the transmission network – a mission involving lead times often in excess of a decade – with complete confidence. Do we believe that the ‘right’ geographical spread of generation, flexible resources and network is something that the market can deliver on its own? Or is it a case of using appropriate market structures as a tool within a wider framework for appropriately developing the energy system?

An obvious further point is that a move to LMP would likely take years to implement and, on its own, would significantly increase revenue uncertainty for generators. This risks creating an investment hiatus at the very time investment in new capacity needs to ramp up to unprecedented levels.

Based on what we’ve read and discussion with a number of experienced industry actors in Britain and the US, it seems to us that there are significant risks around the introduction of LMP in a context of radical change to the nature of generation and need for massive investment. It may be that it could bring benefits in, for example, encouraging the offering of ‘flexibility’ and efficient utilisation of what’s available but only as part of a wider package of measures including, crucially, accelerated network investment. We believe significantly more work needs to be done to understand the practical risks as well as the potential aggregate benefits of different combinations of options, introduced over different timescales.

Whilst a move to LMP and, specifically, nodal pricing may have many theoretical advantages, it must be assessed through the lens of whether the net result would, in practice, support delivery of net zero power over the coming 13 years and meet the expected growth in demand for electricity out to 2050. It must also be asked if alternative arrangements might satisfy the same end.

About the authors

Simon Gill is an independent energy system analyst and an associate of Regen.

Callum MacIver is a Research Fellow in the Department of Electronic and Electrical Engineering at the University of Strathclyde and a contributor to the UKERC research theme on Energy Infrastructure Transition.

Keith Bell holds the Scottish Power Chair in Future Power Systems at the University of Strathclyde and leads the UKERC research theme on Energy Infrastructure Transition.

The authors are working together on a review of evidence and perspectives on what Locational Marginal Pricing might mean for the British electricity sector. Although the review is being funded by SP and SSE, Gill, MacIver and Bell have full editorial independence and take full responsibility for errors and omissions. The final report is expected to be published around the end of October 2022.

[1] Page 28, National Grid ESO, Net Zero Market Reform: Phase 3 Assessment and Conclusions, May 2022, https://www.nationalgrideso.com/document/258871/download

[2] PA Consulting Group, Overview of FTR, April 2003, https://www.cru.ie/wp-content/uploads/2003/07/cer03098.pdf

[3] Page 5, Energy Systems Catapult, Introducing nodal pricing to the GB power market to drive innovation for consimser’s benefit: why now and how?, https://esc-production-2021.s3.eu-west-2.amazonaws.com/2021/10/lQMffRGq-14.10.21-Introducing-nodal-pricing-to-the-GB-power-market.pdf

[4] National Grid ESO, The Pathway to 2030 Holistic Network Design, https://www.nationalgrideso.com/future-energy/the-pathway-2030-holistic-network-design