N.B. This paper does not reflect the views of National Grid ESO, who are Energy UK members.
The Review of Electricity Market Arrangements (REMA) identifies a number of challenges associated with the decarbonisation of the power sector by 2035, including whether sharper locational signals are needed to manage system costs, such as constraint costs. One option being considered as a solution to this particular challenge is the introduction of Locational Marginal Pricing (LMP) in the GB wholesale power market.
In summer 2022, Energy UK set out preliminary views2 on LMP, including the evidence threshold it would have to meet to justify implementation. In light of the evidence published in the last year3, we do not believe that this threshold has been met. The case for LMP, and the evidence underpinning it, does not convincingly demonstrate that the notional benefits clearly outweigh the risks of implementation.
We recognise the potential system benefits that more cost-reflective locational signals could deliver. However, given the potential risks to securing the substantial investment needed to achieve a decarbonised power sector, Energy UK believes that now is not the time to consider LMP further. Instead, options to incrementally improve the power system should be prioritised to support investment in the critical period to 2030.
Once the investment for, and build out of, a decarbonised power sector has been delivered, we acknowledge there may be a need to revisit market arrangements to ensure efficient market operation.
This note sets out Energy UK’s major concerns about the case for introducing LMP and an overview of some of the incremental reforms that could deliver more cost-reflective locational signals through existing mechanisms to achieve similar benefits. This includes reforms to network charging, support mechanisms, the Balancing Mechanism (BM) and the wider use of National Grid ESO’s (ESO) Local Constraint Market.
1 – A unconvincing evidence base
The success of existing market frameworks to attract investment in low-carbon and renewable energy means the electricity system is facing new challenges in adapting to greater levels of intermittency with fewer sources of dispatchable power in the GB electricity generation mix. These challenges are exacerbated by the failure of transmission build to keep pace.
The case for LMP has been presented as a way to manage constraint costs resulting from a mismatch between the pace of generation build and transmission build. It argues that LMP would provide investment and operational price signals based on location that would reduce the cost of constraint management and incentivise more efficient siting and operation of demand and supply. The reality of implementing LMP is much more complicated.
Energy UK is concerned that studies concluding that LMP would deliver net system benefits compare LMP to the status quo, rather than comparing LMP with an alternative market with expected system reforms and developments. Furthermore, conclusions drawn in these studies are based on unrealistic assumptions about how quickly LMP could be delivered without real exploration of the benefits of improvements to existing arrangements, acknowledgement of the impact on investor risk4, or realistic consideration of the cost of implementation for the industry as a whole The complexity and sensitivity in the assumptions behind LMP studies is such that the purported net benefits and distributional impacts are highly uncertain.
1.1 – The base case scenarios in studies recommending the implementation of LMP in GB do not capture the scope for improvements in the current market framework
Counterfactuals in the existing evidence base5 for LMP do not consider the scope for holistic policy-making to manage potential future system challenges, deliver more efficient dispatch and therefore reduce the cost of constraint management. These include but are not limited to: retail reform and the role played by demand, potential new locational constraint markets, improvements to system operation, the siting of hydrogen and CCUS, the potential for green hydrogen to soak up power, the Capacity Market (CM) promoting an increase in storage, system benefits derived from a reformed Contract for Difference (CfD), and the role of the Future System Operator in more strategically planning the future of the power sector, and ensuring it has the power and resources to this effectively.
1.2 – The existing evidence base makes unrealistic assumptions about constraint costs savings under LMP
FTI Consulting’s cost-benefit analysis of introducing LMP in the GB power market is based on an implementation date of 2025, which is an unrealistic assumption. Officials estimate that following a decision to introduce LMP, implementation would take 5-9 years. At the same time, ESO projects that constraints will increase this decade before reducing in the early 2030s with the transmission investment planned.
FTI Consulting’s conclusions therefore overestimate the benefits of an LMP system as the modelling captures constraints cost savings from a time period in which transmission build is significantly less than when LMP could realistically be introduced. We believe that more realistic assumptions would conclude in much lower benefits than presented in FTI Consulting’s study6.
Furthermore, LMP has been presented as a market design that will remove constraint costs. In fact, LMP would only transfer these costs to generators, which would likely require other revenue streams to ensure existing facilities can cover ongoing operational costs and any maintenance required. If other revenue streams are not forthcoming, LMP would reduce revenue and could ultimately lead to early decommissioning. Similarly, for new projects, LMP would put an upward pressure on prices charged by new projects due to reduced revenue expectation for the merchant tail after the investment contract ends (e.g., 15 years in the case of the CfD).
1.3 – The need for an increase in transmission build
We fully accept that there is a mismatch between the pace of generation and transmission build out, and recognise that the Government, Ofgem and ESO have all committed to an overhaul of how network infrastructure is built7. Yet, much of the rationale for the introduction LMP is linked to the current under provision of network infrastructure8. Government should be wary of any purported LMP benefits case which makes an assumption that network build fails to emerge. It is implausible that signals to build infrastructure would not strengthen over time if new infrastructure had not emerged, which in turn would result in substantial erosion of the stated benefits.
Given the urgent need to decarbonise an economy which will be increasingly electrified, we believe that substantially increasing the pace of transmission infrastructure build is necessary under any scenario. LMP should not be a substitute for efforts in this area9 and the benefits of LMP with increased transmission should be considered as these would be much reduced.
2 – Risks of implementing LMP
Energy UK believes that the evidence base being relied on to demonstrate the benefits of introducing LMP in GB not only overestimates its benefits, but also underestimates the challenges, costs and delivery risks of implementing LMP. It is likely that introducing LMP in GB would be more complex, more time-consuming, more costly to implement, and more politically challenging than the existing evidence base anticipates.
2.1 – The complexity of designing LMP for GB
Implementing LMP in GB would come with a unique set of challenges unseen by other markets that have adopted it. This is explored in detail in the University of Strathclyde’s recent study on LMP10. In addition, Energy UK members shared concerns about:
- The compatibility of LMP with a highly developed national retail market, a retail price cap, and CfDs11.
- The compatibility of central dispatch with a much larger quantity of assets and Demand Side Response (DSR) which will exist in future, in particular at distribution level.
- The IT infrastructure required to manage LMP, including the move central dispatch, which would be substantially more complex to deliver and implement than existing systems12.
- LMP markets clearing at day-ahead, without much scope for intraday adjustments to be managed by market participants.
- Insufficient consideration of how Financial Transmission Rights (FTRs) could be given over the long term to support investment cases in the existing evidence base.
- The lack of modelling of wider system flexibility and operability requirements in the existing evidence base for LMP.
2.2 – Lengthy timelines perpetuating uncertainty for investors
Given the level of complexity in designing LMP for the GB power market, the resources required and legislative steps involved for implementation, the time it would take to deliver LMP would be significant (see above). This would perpetuate uncertainty for a significant proportion of the time left to decarbonise the power sector. This could lead to an investment hiatus and put the Net Zero transition at risk.
With the potential for delays to delivery timelines and for emerging issues in early days after a market goes live, it is plausible that an LMP transition would not make any positive contribution to decarbonising the power system by 2035, let alone by a more ambitious 2030 date.
2.3 – An increase in the cost of capital or capital flight
Delivering a decarbonised power sector by 2035 will require significant private sector investment in both generation and network infrastructure. The cost of capital is therefore crucial to this objective succeeding. Increased uncertainty, unpredictable price volatility and the challenge for investors to price risk during a lengthy implementation process is likely to increase the cost of investment or cause capital flight, at a time when GB is competing globally against increasingly attractive markets with clear and supportive policy frameworks13.
An LMP system would also put an initial, unmanageable risk linked to network development on market participants, who have no control over the impact this has on their nodal price. Whether other generators or demand sources choose to locate at their node is also outside of their control. Currently, network underinvestment impacts market participants through their Transmission Network Use of System (TNUoS) charges. LMP would lead to less predictable and more volatile charges, increasing risk and therefore the cost of capital, for market participants.
An LMP system would not change the fact that ultimately, consumers pay directly or indirectly for insufficient investment in the electricity network.
2.5 – Distributional impacts on domestic and non-domestic consumers
A fundamental question remains about the role of demand in an LMP market, the extent to which different tranches of consumers would be exposed to varying electricity prices, and its fairness. Energy UK believes that the existing evidence base has not sufficiently considered the potential political implications of introducing LMP and its compatibility with the highly developed national retail market that exists in GB. While there has been significant political focus on decoupling power prices from gas prices, LMP could have the effect of reinforcing this link for many consumers.
3 – Alternative options
The risks set out above are significant and should not be underestimated. We believe that there are alternative measures to address system challenges which would be significantly easier and quicker to introduce, could deliver tangible benefits for consumers sooner while being less likely to harm investment through market uncertainty.
In any case, policymakers should not prejudge whether LMP is needed without exhausting the full potential of existing arrangements to meet changing system needs. Enhancing current mechanisms through incremental reform would provide investors with a familiar framework to facilitate the unprecedented levels of capital expected to flow into the GB power market. As well as greater network investment, this would include reforming TNUoS charging, the BM, wider use of National Grid ESO’s Local Constraint Market, and reforms to support mechanisms such as the CfD.
3.1 Investment signals
3.1.1 TNUoS reform
Locational investment signals already exist in the GB electricity system within TNUoS charges. Currently, TNUoS signals are delivered in a way that limits their impact on investment decisions for siting. Issues include a lack of cost-reflectivity and short-term forecasting that is subject to change, based on an opaque methodology. This introduces risk for developers and restricts their willingness to respond to the locational signals that TNUoS charges provide.
In order to provide a more effective locational investment signal, a number of reforms should be considered:
- Transparency: the methodology for calculating TNUoS must be made more transparent, including inputs such as network asset data and operational costs.
- Modelling assumptions: the modelling assumptions upon which TNUoS charges are based must be updated to ensure for cost-reflectivity of the future system, including planned network build and growth in generation and demand.
- Predictability: TNUoS must be predictable at the point an investment decision is made. For example, some members suggest setting TNUoS charges from the point of connection for a period of 10 years or more14. In any case, improvements in year-on-year predictability, based on a transparent methodology, could provide significant benefits.
- Volatility: along with revised modelling assumptions and a transparent methodology, any changes to TNUoS charges should be incremental. The possibility of large variations in TNUoS charges throughout the lifetime of a project create uncertainty and hamper investment.
- Stronger locational charges for demand: currently, the locational aspect of TNUoS for demand is small compared to the residual element. In order to provide a stronger locational signal, the locational charge could be made more significant. Some members suggest that TNUoS could be allowed to become negative in areas where there is a surplus of generation.
- Treatment of storage: electricity storage assets could be given specific treatment in TNUoS to encourage siting near areas with net supply.
Any changes would need to be coupled with changes to the planning regime, so that assets are able to site in response to TNUoS signals. In addition, given the materiality of these costs, changes to TNUoS need to give parties a sufficient lead time before implementation.
Many of the above reforms are being considered or progressed under existing industry workstreams, such as the TNUoS Task Force, the Strategic Transmission Charging Reform programme, and Connection and Use of System Code Modifications such as CMP315, CMP375 and CMP413. Government and Ofgem should consider the outcomes of these workstreams when considering further reforms to TNUoS charging in order to deliver more effective locational investment signals.
3.2 – Operational signals
Improvements to the BM and the wider use of ESO’s Local Constraint Market could help reduce the cost of constraints by enabling the dispatch of low-carbon assets and send stronger investment signals for flexibility providers. These incremental reforms would have the benefit of:
- Increasing competition in the BM would help bring down constraint and balancing costs now, rather than in the future under LMP.
- Constraint markets would introduce more visibility for ESO in making dispatch decisions.
- Increasing transparency over dispatch decisions in the BM would allow markets to develop and respond accordingly.
- Improving investor certainty in flexibility markets – through forward markets and transparency in dispatch decisions, and improvements to enable low-carbon assets to be dispatched.
3.2.1 – Improvements to the Balancing Mechanism
The BM is already locational by nature, with assets being dispatched to balance the system based on their location relative to a constraint. A more competitive, accessible and transparent market would create more opportunities for low-carbon flexible assets to help ESO balance a highly renewable energy system, which could reduce balancing and constraint management costs. At present, ESO faces technical challenges to identify and dispatch the most economically efficient actions15.
A number of improvements should be considered:
- More longer-term contractual arrangements between ESO and flexibility providers.
- Widening access to enable more participation from aggregation, demand and embedded generation. This would include addressing barriers to entry and to being dispatched.
- Improving forecasting and transparency allowing the market to respond.
- Visibility of charge status of storage assets to facilitate greater use in constraint management.
- IT upgrades to enable automated re-dispatch and shorter settlement periods.
- Definition of locational flexibility and operability envelopes allowing developers to better meet these requirements and provide long-term investment signals to developers.
Improving, digitising and opening up the BM would be a ‘no regrets’ approach and could be implemented in the short term. These incremental improvements to the BM would help increase competition, provide flexibility to investors with more certainty, helping to manage and reduce costs now, rather than in the 2030s.
3.2.2 – Building on the design of ESO’s Local Constraint Market
Energy UK recognises the progress currently being made by ESO to improve system operability. We believe that there is scope for markets and services to be further developed to enable ESO to use of a wider range of assets and resources to pre-emptively manage constraints.
One way of doing this would be by building on the design of ESO’s Local Constraint Market (LCM) for wider use, alongside the wholesale market and the BM. This would enable ESO to procure locational flexibility ahead of time competitively and reduce the number of locational actions in the BM16.
Potential design features of a Constraint Management Market:
- It would be designed for use on a wider scale and longer-term basis17 than the LCM to provide locational dispatch signals for assets (generation, storage, demand and interconnection) capable of responding to them. Participation would be elective rather than mandatory.
- It would be flexible and agile, with several procurement timeframes: intraday up to gate closure, day-ahead, and longer contracts, providing wider competition to the BM.
- It would be open to BM and non-BM parties, and should be stackable with other ESO balancing services and DNO flexibility products.
- ESO should provide annual forecasts on expected size, location and timing of forecastable transmission constraints to the market – providing a longer-term signal to flexibility providers.
- This market would enable ESO to procure services from flexible assets that can provide them, in contrast to LMP, which would impose a penalty on assets not able to do so.
- It would be adaptable to the needs of the area as these evolve, for example, through transmission reinforcement, constraints shifting or DERs connecting.
- It would help to provide certainty and predictability of costs and lead to better transparency of actions and total costs of constraint management.
- It would help to provide clarity over state of charge data for contracted battery and storage assets.
- It could be rolled out quickly as minimum reform would be required and the functionality of the market already exists.
3.3 – Evolution of the Contract for Difference
Currently CfD generators are incentivised to generate irrespective of the market price, with a negative impact on system costs and market signals. To reduce this impact, more recently signed CfDs have a ‘negative pricing rule’ whereby generators are not paid during periods of negative pricing. Whilst this has benefits in reduced CfD payments and system costs, with more renewables coming on the system, negative pricing rules place risks on renewable generators outside of their control, and this increased risk in turn puts an upward pressure on CfD strike prices.
There is a potential benefit that comes from CfD generators participating in the other markets at times of low price. CfD reforms to that end, e.g. decoupling CfD payments from output, might involve a trade-off with investor confidence, and this should be carefully considered.
If Government decides to investigate such decoupled mechanisms further, this could have the dual benefit of reducing system costs through enabling more cost-effective participation in the BM (as the opportunity cost of lost CfD earnings would no longer be put into bids) and reducing volume risk to enable lower CfD strike prices by removing the detrimental impact of the negative pricing rule with CfDs.
3.4 – Other improvements to GB’s investment landscape
In addition to uncertainty about future market design and the exploration of fundamental reforms, the factors listed below are also contributing to the deterioration of the GB investment landscape, at a time where other markets are becoming more attractive.
- Significant timelines for planning, consenting and grid connections.
- Insufficient transmission build out.
- CfD AR5 auction parameters.
- Competition from global investment policy, such as the Inflation Reduction Act in the US, the European Green Deal.
- Electricity Generator Levy (EGL) extending to 2028, in contrast to the EU’s Revenue Cap ending in summer 2024.
- Uncertainty in the UK ETS.
These should be addressed in addition to incremental reforms to market design in order to meet the objectives set out in REMA.
Energy UK does not believe that the case for LMP and its supporting evidence base prove that such a radical and fundamental shift from existing market design is justified. We would urge the Government to scrutinise the underlying assumptions in the evidence base (including the lack of optimised national pricing counterfactuals), consider the risks of implementation further, and explore more meaningfully the progress that could be made through incremental reforms and other improvements to the investment landscape.
Energy UK recognises the political challenges associated with the build out of transmission infrastructure and reforming the planning regime. However, we strongly believe that LMP is not a silver bullet that will enable the Government to circumvent these problems. Indeed, there is surely a greater political risk in adopting a strategy which may not be deliverable in the timeframe needed, which may increase overall costs of the transition to Net Zero or see a decline in investment in GB energy, which would not remove the need to tackle politically difficult issues, and which itself would raise serious political questions about fairness.
We recognise the potential system benefits that more cost-reflective locational signals could deliver. However, in light of the potential risks to securing the substantial investment needed to achieve a decarbonised power sector, Energy UK believes that now is not the time to consider LMP further. Instead, options to incrementally improve the power system should be prioritised to support investment in the critical period to 2030.
An incremental approach to reforming electricity market arrangements would enable investors to keep working within known frameworks and best support the UK to remain an attractive and competitive market in the global race to Net Zero. Once the investment for, and build out of, a decarbonised power sector has been delivered, we acknowledge that there may be a need to revisit market arrangements to ensure efficient market operation.
About Energy UK
Energy UK is the trade association for the energy industry with over 100 members – from established FTSE 100 companies through to new, growing suppliers, generators and service providers across energy, transport, heat and technology. Our members deliver nearly 80% of the UK’s power generation and over 95% of the energy supply for 28 million UK homes as well as businesses.
1 N.B. This paper does not reflect the views of National Grid ESO, who are Energy UK members.
2 Energy UK’s July 2022 report on The Future of the UK Power Market states that the consideration of sharper locational signals should be based on a strong analysis considering the whole system, and ensure that such a policy would not interfere with investment at such a critical moment in terms of power sector expansion. The report also states that LMP should only be explored where an evidence-based case demonstrates that the issue of locational constraints is not better solved by incremental changes to existing markets, greater investment in transmission infrastructure or alternative interventions.
3 Since REMA was published in July 2022, National Grid ESO and Ofgem, with FTI Consulting and Energy Systems Catapult, have contributed to the debate on locational signals in the wholesale market and produced evidence to support the case for the introduction of LMP. National Grid ESO’s market reform work is available here. Ofgem’s locational pricing assessment, which is informed by FTI Consulting’s cost-benefit analysis (CBA) of introducing LMP in GB, has not yet been published. However, key findings from the CBA were presented to industry in London (6th June) and Glasgow (13th June).
4 Such as a possible investment hiatus and/or higher cost of capital.
5 For example, FTI Consulting’s study does not include an optimised national pricing counterfactual.
6 For example, the headline benefit presented is based on outlier scenarios. ESO’s Future Energy Scenario’s Leading the Way with Holistic Network Design (HND) versus System Transformation with NOA7, which reduces benefits by ~40%.
7 Through the more strategic approach to transmission build introduced under the Offshore Transmission Network Review (OTNR) up to 2030 and the move to a Centralised Strategic Network Plan (CSNP) beyond 2030.
8 As evidenced by reduced benefits under NOA7 vs HND.
9 N.B. The nodal market in Texas has not delivered a reduction in constraints. In fact, constraints have increased substantially. See 2022 State of the Market Report for the ERCOT Electricity Markets.
10 Gill, Simon and MacIver, Callum and Bell, Keith (2023) Exploring Market Change in the GB Electricity System : the Potential Impact of Locational Marginal Pricing. University of Strathclyde, Glasgow.
11 In particular, the complexity of how a fixed mechanism like the CfD would work with an unpredictable one like LMP.
12 Historically, IT transformation projects to improve system operability have been significantly delayed and delivered over budget. See ESO End of Scheme Report, ESO Performance Panel End Scheme review 2021-2023.
13 E.g. the Inflation Reduction Act in the US, the European Green Deal.
14 We note the argument that market participants could hedge equivalent risk under LMP through Financial Transmission Rights. However, this is not the reality in existing LMP markets.
15 Gowdy, Johnny and Gill, Simon and Brundrett, Ellie (2023) Improving locational signals in the GB electricity markets, Regen
16 Gowdy, Johnny and Gill, Simon and Brundrett, Ellie (2023) Improving locational signals in the GB electricity markets, Regen
17 In particular, to help address the period of peak constraints projected in 2027-2032.