Consultation response
BEIS Review of Electricity Market Arrangements
Nov 2022
Authors: Simon Gill, Callum MacIver and Rob Gross
As the dust settles on the second REMA (Review of Electricity Market Arrangements) consultation, this blog reviews the debate on locational signals, their importance for flexibility, and the need for a more concrete articulation of what could be improved alongside a national wholesale market.
It feels like we have been debating the options for improving locational signals in the electricity system for a long time. The current iteration of the debate kicked off properly in spring 2022 at the start of the UK Government’s Review of Electricity Market Arrangements (REMA), although by that stage National Grid ESO (as they were called at that point) and the Energy Systems Catapult had each already published work on a case for change.
The original REMA consultation laid out three potential approaches: nodal or zonal pricing in the wholesale markets, or alternative routes to provide locational signals alongside a national wholesale market.
After two years, it still doesn’t feel like we are close to agreement on the best way forward. However, some progress has been made.
In that time we’ve had an intense debate on the value of locational wholesale pricing in either nodal or zonal form. Two of the authors of this blog along with colleague Keith Bell, carried out a detailed review of Locational Marginal Pricing in 2023, considering the challenges and opportunities for implementing it within the GB system. The debate has also produced several studies presenting quantitative modelling results based on nodal and zonal approaches, some of which include large estimates of socioeconomic welfare and consumer benefit (see reports from FTI consulting, AFRY, and LCP Delta).
Others have voiced strong opposition against locational wholesale pricing, arguing that it creates significant uncertainty and risk that would be challenging to hedge and would have significant, detrimental impacts on investment in low carbon technologies.
After considering this evidence, the UK Government removed the option of full nodal wholesale pricing from the table. In the recent second REMA consultation, the debate has been reformulated around two enduring options: zonal wholesale pricing, and what the consultation calls ‘alternatives to zonal pricing’.
It seems to us that there are two major barriers remaining before we will be in a good position to reach a decision on which option to implement.
Firstly, there remains disagreement on the overall value of locational price signals. Whilst most people agree that both in principle and in practice there could be benefits from improved locational price signals (whether delivered through zonal wholesale pricing, or an alternative route), there remains disagreement as to the magnitude of those benefits and the trade-offs against other considerations.
For example, stronger locational price signals could translate into a higher cost of capital, particularly for renewable generators developing in areas with high renewable resources, well developed project pipelines and supportive planning and consenting regimes. If, despite these signals, we still need investment in these areas to meet wider ambitions, particularly the goal of decarbonising the electricity system by the mid-2030s, the impact of increased cost of capital has the potential to wipe out benefits arising from more efficient wholesale market operation. An even worse outcome is that the increased uncertainty slows investment and, ultimately, our progress towards overarching goals.
The second major barrier to good decision making is that we lack a full articulation of what either of the two retained approaches might actually look like in practice.
Zonal wholesale pricing could span everything from a framework based around two decentralised markets linked by cross-zonal interconnection (much like the way bidding zones in the European Single Electricity Market are linked) to a model based on full central dispatch with up to a dozen smaller zones (similar to the design of the Scandinavian zonal market).
The alternatives to zonal are even less well defined. In its consultation, the UK Government articulated four main high-level mechanisms: network charging, network access, improved constraint management and improved cross-border interconnector dispatch. There was, however, little concrete detail on their design, the principles which would underpin them, or how they might be combined into a coherent package.
The lack of detail on locational signals, particularly how to deliver them alongside a national wholesale market, is a significant gap this far into the REMA process. If we do not have clearly defined options for reform, how can we properly assess them and make good decisions?
Flexibility can be described as the ability of assets to adjust their power output or consumption in accordance with variations in conditions either due to forecasts (in which case an action is scheduled) or unexpected events (in which case the flexibility has to be reactive).
Historically, the provision of flexibility has tended to be bundled with power generation, particularly from fossil fuel power stations. These stations had various inherent capabilities to run flexibly and support system operability in their normal operation. Revenue streams specific to the provision of flexibility could somewhat be treated as an afterthought. Many providers built their business case primarily on the bulk sale of electrical energy. Revenues from ancillary services markets, the Capacity Market, and actions through the Balancing Mechanism, were additional ‘nice to haves’. This, combined with the fact that during the first decade and a half of this century network constraints were relatively limited, has led to the situation today where there are few locational signals for flexibility.
This is critical for three reasons. First, to minimise the use of unabated fossil fuels, we need to replace the flexibility of fossil fired generators with low carbon options and ensure these are located where they are effective for the system. This includes the need to ensure a set of arrangements that can support technologies like energy storage which, unlike power stations, are ‘flexibility only’ assets and need to build their business cases entirely on flexibility revenue streams.
Second, we see an increasing demand for flexibility to reflect the variability of renewable resources. This sets much of the context for defining the characteristics which our flexibility fleet needs to exhibit including ‘schedulability’, the persistence of certain actions, overall scale, and location.
Third, whilst the debate around locational flexibility is often framed as a trade-off with network capacity (more flexibility can reduce the need for network) the interaction between investment in flexibility and networks is more nuanced and needs careful consideration. The network also plays an important role in allowing the system to access flexibility. The fast and controllable response of a pumped storage station in Scotland or Wales to the sudden trip of, say, an interconnector in south East England would be of no use without sufficient transmission capacity between the two regions.
Defining the alternatives to zonal is important because we need well articulated concrete proposals for both options if we are to make good decisions through the REMA process.
It is important for a second reason: even if, ultimately, we decide that zonal pricing is the most appropriate way forward, introducing zonal pricing will take time. In the interim it will be important not simply to sit and wait. If we are to get close to our ambition of a fully decarbonised electricity system by 2035, much of the heavy lifting needs to be done before the end of the decade, on a shorter timescale than the more comprehensive reforms needed to implement zonal would be possible. (If the government chooses to pursue zonal pricing, the process would involve a white paper and primary legislation change, requiring Parliamentary time. As a result, it is unlikely that LMP could be delivered until around the end of the decade). An important question is what impact would failure to improve locational signals before then have?
One of the challenges of defining an alternative is that there is no single, neatly defined option. Rather, there are many alternatives that sit across a multitude of frameworks, from regulated network charging, through low carbon support schemes, to the way the electricity system’s varying assets are planned. The types of locational signals vary as well: there are options which would deliver a market price signal (for example through ancillary service markets) or a regulated cost signal (for example network charging), and options that deliver strong non-price signals (such as the potential for strategic planning approaches to play a more active role in defining where certain technologies are acceptable and where they are not).
Figure 1: an overview of the commercial and regulatory arrangements within which locational signals could be delivered
Figure 1 shows the full set of components which together make up the set of commercial and regulatory arrangements through which locational signals could be delivered. It includes the wholesale market itself, centrally organised markets for ancillary services and capacity, and legislative and policy structures. All of this sits against the present day and evolving physical, demographic and social background.
Each element could be used to deliver locational signals and, to a greater or lesser degree with different granularities of temporal variation, many of them already do. A key challenge is to articulate one or more coherent package that could deliver appropriate locational signals with a suitable balance between more efficient markets and the various other considerations involved in delivering overarching societal objectives.
One of the first challenges that comes up in defining an appropriate model is agreeing the ultimate objective. In previous work by Gill, MacIver and Bell reviewing Locational Marginal Pricing, recommendation 15 stated that “The final suite of reform options that is brought forward from the ongoing review process should be the package that best addresses the overarching objective of the power system, which this report suggests to be:
Ensure that, by 2035, net production of greenhouse gases on the GB electricity system is negligible while supplying electrical energy with sufficient security and resilience at lowest total cost to energy users over the medium to long term.
In achieving this objective, reform of energy markets should consider their interaction with a wider set of economic, social and environmental policies and how development of the energy system makes the most of opportunities for the whole economy, ensures fair access to and affordability of energy, supports regional development across GB and provides appropriate protection for natural capital and ecosystem services.” (page 18)
This is a slightly longwinded way of reiterating both the traditional energy trilemma of cost, sustainability and security of supply, and of putting it in the wider context of economic and social considerations.
It is important to focus on ultimate outcomes because efficient market frameworks are not the goal in their own right but are only tools which we can choose to use in particular ways to deliver positive outcomes.
Take the first part of our articulation of overall objectives: “Ensure that, by 2035, net production of greenhouse gases on the GB electricity system is negligible”. This means we need significant investment in wind and solar; in schedulable low carbon technologies like hydrogen power stations (high flexibility), natural gas or bioenergy powered generators with carbon capture and storage (which might have medium levels of flexibility) and potentially nuclear (almost inflexible); and other forms of flexibility such as batteries, long duration energy storage and interconnection.
We need to ensure these investments are made, despite significant uncertainty about the system in which they will come into operation. For example, offshore wind farms at inception stage today will connect into the electricity system towards the middle of the next decade. At that point, whilst we have a series of outline plans for the transmission network brought forward by the ESO in recent years (HND and Beyond 2030), a project investor is likely to see considerable risk arising from a delay to or an outright failure to develop some of those links.
That uncertainty, coupled with the strong societal need for renewable investment, highlights a critical trade-off. If we expose projects to stronger locational price signals, for example by removing firm access rights (hence removing curtailment payments from those generators), we have the potential of, in a technical sense, a more efficient energy market but we may increase the risk of not getting the investment we need.
The issue is exacerbated by the financial context for many low carbon projects. Many of these technologies, including wind, solar, carbon capture and storage (CCS) based generation, nuclear and long duration energy storage, tend to have higher ratios of upfront investment costs compared to ongoing operational costs. For example, for a gas fired power station around 9% of the cost of the electricity it produces is related to upfront investment; for onshore wind the equivalent figure is 63% and for solar it is 75% (see previous work by Gill, page 49). In the case of wind and solar, this is the flip side of the more commonly quoted characteristic: zero short run marginal cost.
Given the advanced state of development of generation projects in particular sites, stronger locational price signals are likely, unless mitigated by other arrangements, to translate to a higher cost of capital and that cost of capital will be applied to an increasing fraction of the total cost of energy. However, whilst minimising the cost of investment is important, it represents only one element of cost and cost itself is only one element of the trilemma; taking the wider economic and social context into account we are also trying to maximise value.
At some point, without stronger signals on where generation on the system is placed relative to transmission constraints, the cost and practical challenge of re-dispatching a market that has cleared without any consideration of congestion in the one hour before delivery will become material.
Some argue the point at which the balance tips towards the need for stronger locational price signals has already been reached and that, without intervention, the costs and challenges will only grow over the coming years.
The conclusion has to be that there is a real and material trade-off between the benefits of stronger locational signals and the potentially detrimental impact on investment. We need to find a balance between the two.
This focus on trade-offs is one of the principles behind a new UKERC project. It takes as its starting point the need to systematically articulate a set of measures that could deliver appropriate signals to flexibility, including locational signals, retaining the fundamentals of current wholesale market arrangements. This will include improving operational efficiency, reducing constraints and constraint costs, maximising incentives for investment in flexibility, and avoiding perverse incentives.
The project team is currently reflecting on how we have ended up where we are today before undertaking a critique of the current ‘case for change’. The aim is to prioritise the most important shortcomings related to locational signals in order to understand which specific elements of the commercial and regulatory arrangements are in most urgent need of reform.
We will then explore a long list of options to adjust the current suite of locational signals, assessing each option against the overall objectives for electricity system development and identify pros, cons and trade-offs.
The implications for any reform package will need to be considered for individual types of investment – for example, the impact on a gas CCS power station will be different from that on a pumped storage hydro plant or a floating offshore wind development. The project will use archetypical technologies (e.g. offshore wind to represent variable renewables) to illustrate the implications of reform on different technologies.
Finally, the project will deliver a set of recommendations and conclusions to support UK Government, the ESO, Ofgem and the wider sector in moving towards a position from which we can collectively make an evidence-based decision on the most appropriate way to deliver locational signals alongside a national wholesale energy market.
About the authors:
Simon Gill is an independent energy consultant, with nearly 15 years of experience working with regulated energy network companies, academia and government. View Simon’s LinkedIn profile.