On 24 May 2022, National Grid ESO (the “ESO”) published the Net Zero Market Reform – Phase 3 Assessment and Conclusions (the “ESO Report”). The ESO Report is part of the ESO’s Net Zero Market Reform programme (the “Programme”) established in 2021 to examine the changes to current Great Britain electricity market design that will be required to achieve net zero. The ESO Report identifies that the current market design is no longer fit for purpose, and presents evidence establishing that nodal pricing combined with central dispatch is the most efficient, effective and appropriate net zero market design.
Current market design
The existing market design is known as the British Electricity Trading Transmission Arrangements (“BETTA”). BETTA is an extension of the New Electricity Trading Arrangements (“NETA”), which was established in 2001. NETA was, and indeed BETTA is, based on generators and suppliers contracting bilaterally, or via spot markets, independently of the ESO, under the premise that all generators, regardless of location, can serve load anywhere in GB. Generators inform the ESO up to Gate Closure of their dispatch schedule, and the ESO is responsible for fine-tuning the dispatch of generation to ensure continuous energy balance and protect the technical limits and security of the system. The ESO resolves congestion that arises by ‘redispatch’: instructing select generators and/or loads to change their schedule via the Balancing Mechanism, amongst other tools.
The case for change
The past two decades have seen a radical shift in the proportion of intermittent renewable generation in GB’s electricity mix, from less than one percent in 2001 to just under 30% in 2020, with estimates that this could rise to 85% by 2035. In addition, much of this intermittent generation is located at the network periphery (such as offshore wind in Scotland and distribution connected solar in rural areas). As a result, the ESO has identified the following four key issues with current market arrangements:
- Rising constraints costs - the premise that any generator can serve load at any location does not reflect reality, as increasingly generation output exceeds network capacity. This has led to the annual cost of managing congestion on the transmission network to increase 8-fold from £170m in 2010 to £1.3bn in 2022.
- Inefficient redispatch - the ESO frequently redispatches more than 50% of demand to solve locational constraints arising from renewable energy being transported to demand centres. This comes at a cost. Indeed a recent report published by Energy Systems Catapult (the “ESC Report”) estimates that £0.5bn of the £1.3bn spent on balancing the system in 2020 was due to managing constraints.
- Perverse incentives to flexible assets – interconnectors and storage can be incentivised to flow in a direction that exacerbates constraints, for example when the single national price is sufficiently high the current market design incentivises European markets connected via interconnectors to export to GB, even during periods of high renewable generation in the relevant region.
- Wasted potential of flexibility from both supply and demand - the single national price provides an averaged view of supply and demand, which means flexible assets do not receive accurate signals to alleviate constraints.
In Phase 3 of the Programme, the ESO has identified that the issues listed above are arising because participants in the GB market are not exposed to locational signals to inform trading decisions in operational timescales. This means that the wholesale market outcome and the physical constraints of the system are increasingly pergent.
Nodal pricing pides the national network into different nodes, with every transmission system injection point, offtake point, and transmission line intersection at transmission substations, typically defined as nodes. Each node has different prices, calculated by a central algorithm (used for central dispatch), reflecting the full cost of supplying an incremental unit of consumption at each node per settlement period.
The objective of nodal pricing is to ensure the least cost of energy balancing across the system while ensuring transmission constraints are respected. Further, given the granularity of nodal markets, if applied to the whole transmission network, almost the full cost of resolving transmission constraints can be embedded in wholesale energy prices.
The ESO Report states that nodal pricing, combined with central dispatch, would be the most effective option to address the issues the current system faces for the following reasons:
- Value for money – under BETTA, when generators are curtailed due to transmission constraints, they are ultimately compensated by consumers via BSUoS charges. Nodal pricing however removes financial transfers from consumers to ‘constrained-off’ generators since assets whose output would cause constraints will not be dispatched. In addition, 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, avoiding the need for redispatch following Gate Closure and ensuring the efficient use of interconnectors. This is supported by the ESC Report, which suggests that organising markets to better reflect the locational value of electricity could realise cost savings for electricity users of £30bn to 2035.
- Full-chain flexibility – under BETTA, assets lack visibility of near real-time variations in local supply and demand and as such cannot be incentivised to address local transmission constraints through the price of energy. Nodal pricing provides an accurate locational signal for flexible assets to optimise against in near-real time. Flexible assets are therefore incentivised to help mitigate constraints and to shift demand to periods of high local supply. In addition, nodal pricing removes the perverse incentives for assets with two-way flows, such as interconnectors and storage. Under BETTA, these assets could be incentivised to flow in a direction which exacerbates constraints. However, locationally accurate wholesale signals would enable storage and interconnectors to respond to price signals that reflect the system conditions, such that they behave in a way that supports the system.
- Adaptability - changes in supply, demand and network conditions are automatically reflected in nodal prices as opposed to the need for constant interventions under the current system. Nodal pricing could also potentially be applied to lower voltage levels, with improved monitoring and control at the distribution level facilitating growth in distributed energy resources.
- Investor confidence – in nodal market designs, market participants can partially hedge their exposure to locational price differences through financial instruments such as Financial Transmission Rights (“FTRs”), which give the holder rights to congestion rents between two nodes or zones.
In addition, the ESO believes central dispatch with self-commitment would enable the full resource of the wholesale market to be efficiently deployed to meet balancing requirements by co-optimising energy and reserves and levelling the playing field for all types of energy resource and market actors, including new entrants and non-traditional resources such as demand response.
For the average consumer, the reforms will be a welcome change, especially if they can deliver savings equivalent to over £1000 per household as forecasted by Energy Systems Catapult. Industrial and commercial customers could also benefit from lower energy costs due to lower balancing costs and a more efficient system. This is a particular focus for the Government in light of the soaring costs of energy across the country (see our commentary on the Queen’s speech here).
Nevertheless, these reforms will be a blow for some. For certain generators (particularly offshore wind in Scotland and the north of England) nodal pricing will undoubtedly negatively impact the rate of return on their investments. When coupled with the recent announcement that the Government is considering extending the windfall tax announced for oil and gas companies to electricity generators (although this has not yet occurred and indeed may not in fact be implemented), larger scale solar and offshore wind developers who benefit from the single national price may well consider these reforms simply to be more unwelcome news.
Finally, the ESO notes that some stakeholders raised concerns over a potential increase in Weighted Average Cost of Capital (“WACC”) on renewable development project costs in nodal markets due to forecasting uncertainty, for example new transmission capacity build could significantly alter nodal prices. Nevertheless, the ESO states it did not find or receive firm evidence to suggest that nodal pricing would raise the cost of capital for investment in key technologies. Nor did the ESO’s consideration of other jurisdictions which have deployed nodal pricing reveal historic evidence of an enduring negative impact on investment.
The ESO believes it is credible to implement nodal pricing and central dispatch by 2027, but recognises any decision on reform of the operational market design would be subject to extensive stakeholder consultation and detailed assessment by BEIS. The Government recently announced in the Energy Security Strategy that BEIS will be undertaking a comprehensive Review of Electricity Market Arrangements. In addition, Ofgem is currently undertaking a technical assessment of nodal pricing in GB which will include analysis of the costs, benefits and potential distributional impacts. The ESO plans to work closely with BEIS and Ofgem in both of these projects, with high-level options for reform to be set out in Summer 2022.
Much of the detail, including what additional market reforms are required to complement nodal pricing, remains to be seen. Equally, there are a number of stakeholder concerns identified in Phase 3 that must be further investigated, such as how nodal pricing would impact different cohorts of market participants, and to what extent different consumer segments should be exposed to locational price signals. The ESO will be tackling these questions in Phase 4 of the Programme, which is now in its early stages.