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Locational energy pricing in the GB power market

Fully decarbonising the electricity system to help meet Britain’s Net Zero emissions target will require significant investment in generation, networks and flexible energy resources.

In March 2021, Energy Systems Catapult (ESC) published its reform proposals for GB’s future power market – in Rethinking Electricity Markets – EMR2.0 – based on an innovation-friendly and consumer-focussed approach. Among the recommendations, we proposed that BEIS and Ofgem focus on achieving more efficient, dynamic and granular market signals in short-term wholesale markets to reflect power system status accurately by time and location. Improved price signals are key to improving system efficiency and achieving Net Zero at least cost.

Since March, ESC has undertaken a deeper assessment of locational energy price signals, with support from CEPA and TNEI. The evidence and our conclusions can be found in two reports, summarised below:

Introducing nodal pricing to the GB power market to drive innovation for consumers’ benefit: Why now and how?

by Energy Systems Catapult , published October 2021

This report aims to raise awareness of nodal pricing as the first best approach to signalling locational value in a more deeply decarbonised, decentralised, and digitised electricity system. Our work suggests that adoption of nodal pricing in future GB power market design will be highly valuable in enabling an efficient transition to a net zero grid in Great Britain (GB).

The key advantage of nodal pricing is that it encourages generators and providers of flexibility to locate and operate assets (e.g. generation or storage) efficiently, taking account of the real physical constraints in the network. Over time this is likely to lead to more efficient location of new resources and efficient expansion of the network. It will reward innovation and development of flexibility in locations where it is most valuable to the overall system.

Nodal pricing (also known as locational marginal pricing (LMP)) involves determining market clearing prices for several locations on the transmission grid, called nodes. The price calculated for each node reflects the locational value of energy, which includes the cost of the energy and the full cost of delivering it including energy losses in networks and network congestion. Nodal prices are determined in real-time using an algorithm to calculate the incremental cost of serving one additional MW of load at each respective location subject to system constraints (e.g. transmission limits, maximal generation capacity).

Nodal pricing has been adopted in a number of jurisdictions around the world and enables the signalling of locational value mainly through short-term wholesale electricity prices (i.e. spot prices), instead of in network charges. We propose that nodal pricing be introduced as part of a wider reform package, as detailed in ESC’s recently published report Rethinking Electricity Markets – EMR2.0: a new phase of innovation-friendly and consumer-focused electricity market design reform (Keay-Bright & Day, 2021).

Recommendations

Recommendation 1: NGESO should be asked by BEIS and Ofgem to commission a detailed study of the introduction of nodal pricing in the GB power market, encompassing a detailed assessment of the cost benefit case and the implementation and transition practicalities.

Recommendation 2: Transition to nodal pricing at transmission level as soon as feasible as part of a wider reform package to drive innovation through open, competitive and high-performing markets. See ESC’s recommendations for consumer-focused market design reforms. The assessment of how to implement nodal pricing in GB should include consideration of shorter time frames for scheduling and settlement (e.g. 5 minutes), and the extent to which trading in short-term electricity markets should be mandated (i.e. mandatory pool).

Recommendation 3: Transition directly to nodal pricing, not via zonal pricing. Experience from other jurisdictions suggests that reforms to locational pricing are complex and disruptive, but worthwhile and that it makes sense to transition directly to full nodal pricing. The US switched early from zonal pricing to nodal pricing and hasn’t looked back, while progress in implementing zonal pricing within EU countries has been slow and challenging.

Recommendation 4: Establish the independent future system operator (FSO) without delay and ensure it has the functions to efficiently implement nodal pricing. Options for integrating the roles of market operator and system operator within the FSO entity, as in US markets, should be considered.

Recommendation 5: An independent market monitor should be established to improve the performance of power markets in consumers’ best interests. Ensure the market monitor is adequately resourced with necessary capabilities. If some locations exhibit market power, then enhanced market monitoring will be necessary. Continuous feedback through the market monitor, to the key decision-makers responsible for aspects of market performance (i.e. BEIS, Ofgem, FSO), will facilitate agile decision-making, swift action against market power and timely market development. Strong independent market monitoring can also help to build  investor confidence and public acceptance of market operation, reforms and consequent prices.

Recommendation 6: Develop a roadmap for locational signals at distribution level and the institutional structure, role and responsibilities of DNOs, the FSO and any other future entities needed (e.g. DSO, regional entities). Many innovators are basing their business models on the current market arrangements including the latest TCR decision and upcoming NAFLC decision. A roadmap and clarity on the target model for locational signals at distribution level and possible pathways would help innovators manage regulatory risk and develop more robust business models.

Recommendation 7: Reform planning arrangements to complement nodal pricing to cost-effectively develop and fund the network we need. Optimising locational investment decisions will require changes to the planning permissions rules and processes, the responsibility for which sits with national and local governments. Strategic planning/coordination needs to be improved at national and local level (e.g. Local Area Energy Planning (LAEP) interfacing with, and being informed by, more market signals that reflect locational value

Recommendation 8: Evolve reliability arrangements to work with the emerging digitalised and distributed energy system under nodal pricing. Nodal pricing is likely to improve the market’s ability to address physical reliability, but it is likely that the policy mechanisms for reliability and resource adequacy will also need to evolve. This evolution should be designed to mesh with much more developed locational market signals.

Recommendation 9: Combine nodal pricing with robust time and location-specific tracking of carbon (content or intensity) through the electricity system and settlement process ESC proposes combining more granular market signals, by location and nearer to real-time (e.g. 5 minute scheduling and settlement), with an outcome-based carbon policy mandate on retailers/offtakers of electricity. Such a policy framework would require arrangements to track carbon accurately through electricity trading and settlement systems.

Recommendation 10: Design targeted provisions to ensure fairness and address impacts on low-income consumers. Transitional arrangements to dampen distributional impacts may be necessary, such as options for combining nodal prices and flat prices for flexible and non-flexible users/resources, introducing nodal pricing on an opt-in basis with levelling up of bills using credits/charges or targeted support for vulnerable consumers in adopting low/zero carbon solutions.

Recommendation 11: Provide temporary support to incumbents during the transition to nodal pricing. The definition of access rights may need to be redefined if locational energy pricing is introduced. Under uniform pricing, generators implicitly have access (at least in terms of pricing) to the entire network, whereas under nodal pricing generators are only guaranteed unconstrained access to their node (and the respective price). Temporary mitigation measures of compensation arrangements have been employed in other jurisdictions to facilitate the transition.

Locational Energy Pricing in the GB Power Market

by CEPA and TNEI (commissioned by Energy Systems Catapult), published March 2021

This report explores the role that locational price signals can play in minimising the cost of the future energy system. The focus of the study is on the role of energy markets and network use-of-system tariffs in offering locational price signals in operational timeframes.

Three potential approaches (‘straw-persons’) were developed to help explore market design questions and issues. Each straw person offers highly targeted signals of locational value in operational timeframes compared with the current arrangements in the GB energy market. In principle, each of the straw-persons is capable of enabling a net zero electricity system, but each also offers different costs and benefits.

Key points

  • Nodal pricing is the preferred option for ensuring efficient dispatch of resources in operational timeframes and offers high potential for new business model innovations, but it may not be viably applied at lower voltage levels at present. Successfully introducing nodal pricing in the GB energy market would require careful consideration of the level of voltage below which nodal pricing would not apply, as well as establishment of in-depth market monitoring. Behind the node, locational signals can be sent through either local flexibility/energy markets or distribution network charges, though locational marginal pricing could reach lower voltages in time with growth in distributed energy resources and improvements in data, digitalisation and network monitoring.
  • In relatively unconstrained systems, zonal pricing may achieve comparable outcomes to nodal pricing in operational timeframes without the risk of generator market power inherent in nodal pricing, and with far less change required to current system roles and processes to enable nodal pricing. However, constraints are expected to increase considerably over time due to high growth in distributed energy resources. Experience in other jurisdictions shows it can be highly disruptive and challenging to move to zonal pricing before moving again to the more sophisticated nodal pricing. It could therefore be preferable to move straight to the economically superior nodal model despite the major change, which would need careful management and transitionary arrangements. If zonal pricing is introduced, however, care needs to be taken to minimise the risk of inefficiencies from zone definitions, ensure consistency between day-ahead and balancing markets, and avoid double-counting between price signals in wholesale markets and in locational network tariffs.
  • Much more sophisticated network use-of-system tariffs could be developed but they are still unlikely to accurately reflect the cost of energy supply in operational timeframes and will be second best compared to nodal pricing. Nevertheless, they can usefully complement nodal or zonal prices at lower voltage levels. Network tariffs also offer useful longer-term investment signals.

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