On 7 March 2023, the Department for Energy Security and Net Zero (“DESNZ”) published its response to the July 2022 review of electricity market arrangements (“REMA”) consultation, the Government’s major review of the design of the UK’s non-retail electricity markets. REMA is intended to ensure that the power markets are fit for purpose for driving decarbonisation and shoring up security of energy supply in a cost-effective way. Government’s response to feedback on REMA shows that this is very much a work in progress. There are significant challenges ahead, not least determining whether the sum of incremental improvements or a complete transformation of the electricity market is the better approach. Government has ruled out a small number of options which were under consideration in its original consultation but most other options remain open for further consideration.
Over two hundred responses were submitted from a wide range of stakeholders including generators, developers, academics and trade organisations, reflecting the breadth of the potential impact of REMA outcomes and the number of parties who need to corral around a solution. There is clearly consensus on the need for change. The current system, having ultimately grown around fossil fuel generation, is not set up to on-board the volume of low carbon generation required to reach net-zero nor can it accommodate the flexibility crucial to integrating more renewable energy sources. Further, to ensure stability and security, the system needs to be able to better balance supply and demand by shifting consumption or generation in time or location. Respondents not only agreed with Government on the case for reform and the challenges identified but also highlighted additional challenges regarding the need to maintain investor confidence, not to over-complicate the solutions and to ensure cohesion with interdependent policy areas.
Wholesale market and pricing
Such fundamental reform is under consideration because there is a growing mismatch between how the UK electricity markets are structured and how renewable and other low carbon technologies operate. An example is the determination of electricity pricing.
Currently the wholesale electricity price is determined by the cost of the most expensive unit of generation procured. As gas power plants are usually the most expensive generators, this effectively means that the price of gas generation sets the market price for all generators, including those who have much lower cost bases, such as offshore windfarms.
The Government is seeking to address this imbalance currently with the electricity generator levy (see our article here for more information) but structural reform is needed to decouple gas and electricity prices given the longer-term outlook and aims to decarbonise the electricity market.
The response confirms that Government will not take forward a pay-as-bid pricing option. The pay-as-bid option would mean that Generator A could bid a higher price than Generator B in the electricity balancing market, for example. Even if both bids are accepted, each would only achieve the price they have bid, rather than the higher price bid by Generator A. Government discounted the pay-as-bid pricing option as it considered the risk of tactical bidding and the lowering of investor confidence to be too high.
Moving more generation on to private law contracts for difference (“CfDs”) is one option alongside the creation of a green power pool administered by the System Operator which would isolate renewable generation from the rest of the market. CfDs pay generators a guaranteed price for their power, which incentivises investment in low carbon technologies by protecting developers of such projects (which typically have high upfront costs) from volatile wholesale electricity prices, providing greater certainty and stability of revenues. A green power pool could allow industrial and commercial consumers to access renewable electricity at a lower but potentially more variable price than in the wholesale markets.
The wholesale electricity price is currently the same throughout the UK, regardless of where the electricity comes from or where it is consumed. This arrangement results in several inefficiencies, including that the wholesale electricity price does not incentivise market participants to operate and locate in a way that is consistent with the physical needs of the network (i.e. energy is not generated where it is needed). These inefficiencies cause significant operational and grid balancing issues, such as increased network constraint costs (these are amounts that the System Operator pays generators to reduce their electricity output when electricity output exceeds network capacity (referred to as network congestion)).
Network constraint costs, as well as the costs of any other investment in transmission capacity to reduce network congestion, are passed on to consumers and will continue to rise as new renewables generation is added to the network. To address network congestion, the Government is considering shifting from national pricing to locational pricing through the adoption of either zonal or nodal pricing.
Zonal pricing divides the network into several different zones or regions (typically determined by reference to the largest geographical area within which market participants can trade energy without network congestion) and assigns a single price for electricity in each zone. All generators within a particular zone receive the same price for their electricity, regardless of their location within the zone. Consumers within the same zone also pay the same price for their electricity. Zonal pricing is typically implemented when the network is not highly interconnected and generators and consumers are geographically dispersed.
Nodal pricing, on the other hand, divides the network into hundreds or thousands of nodes and assigns a different price for electricity at each individual location or node within the network. This means that the price of electricity can vary depending on where it is generated and where it is consumed. Nodal pricing considers the specific physical characteristics of the network, including the location of transmission lines and generators and the amount of congestion on the network.
Both zonal and nodal pricing potentially allow (at differing levels of granularity) for more efficient use of the network and can encourage generators to locate in areas where they can produce electricity more cheaply. Proponents of locational pricing also believe it will help to resolve network congestion and ensure the network operates more efficiently, reducing the costs of dealing with constraints.
The implementation of zonal and or nodal pricing is not, however, without potential challenges including (among others) that locational pricing is far more complex than the current national price system and requires a more sophisticated market design and infrastructure, which the System Operator will need to be equipped to manage. Furthermore, renewable energy generators such as solar and wind power cannot simply relocate to areas where electricity demand is greater as their location is determined primarily by weather conditions. Likewise, future dispatchable power generation with carbon capture, will also be similarly location-constrained due to the need for access to CO2 transport and storage infrastructure.
The Government response on zonal and nodal pricing was inconclusive and indicated that further consultation was required.
Driving investment in low carbon technologies
A rapid scale up in low carbon electricity capacity is needed to help meet the UK’s net-zero targets and specifically to decarbonise the electricity sector by 2035. There is not enough revenue within the current market to meet the investment needed and as a result, support for low carbon technology is vital. Government has said in its response that, in the short-term, it will not be further considering obligations upon electricity suppliers to purchase a certain amount of low carbon power, or to purchase it at a particular time, as a mechanism for driving increased investment in low carbon technologies or for increasing flexibility. The role of suppliers and potential requirements upon them is still under consideration to support other aspects of REMA, however.
One option which was highlighted by respondents was the potential to support and expand the power purchase agreement (“PPA”) market. Renewable energy generators enter into either CfDs or PPAs, the latter being private contracts for delivery of power to one particular supplier or consumer. Government is considering, in the light of responses received to REMA, whether to provide support to facilitate the growth of the PPA market as a means of accelerating the pace and scale of investment in low carbon technologies and what form this stimulation could take.
While noting the success of the current CfD scheme in building the UK’s renewable generation capacity, Government will continue to consider various options for centralised contracts (including the CfD) with payment based on output and with payment decoupled from output as the main mechanism for driving mass investment in low carbon technology. Increasing exposure to market pricing is likely to increase financing costs and potentially cost of capital for low carbon generation projects but benefits may include making generators more responsive to market signals and incentivising co-location with storage. Other suggestions on centralised contract design included a “soft cap” where revenue could be shared between generator and consumer, a mirroring of the revenue support mechanism for interconnectors or a cap flexing with the wholesale price.
In the next phase of REMA, Government will expand its thinking in various areas including options for the introduction of locational signals. A second consultation is expected during 2023.