The UK Government’s Department for Business, Energy and Industrial Strategy (“BEIS”) has published a wide-ranging consultation on the most significant piece of electricity market reform in a decade. The Review of Electricity Market Arrangements (“REMA”) has been published in the context of rising energy prices, questions over UK energy security and a pressing need to decarbonise in order to meet the UK’s net zero obligations. The central vision of REMA is to deliver fundamental reform to GB’s electricity market arrangements so that they facilitate decarbonisation of the electricity system by 2035 whilst ensuring security of supply.
We set out below the key issues that BEIS is seeking to address with REMA and key areas of focus for industry participants.
The consultation (the “REMA Consultation”) closes on 10 October 2022. Details of how to respond, as well as the full text of the consultation are available here.
1. Context for reform and Key Objectives
As well as setting out the terms of the consultation on future reforms, the REMA Consultation provides useful context and background on BEIS’ views on the current state of, and the issues with, GB’s electricity sector.
REMA aims to:
- reduce UK dependency on imported fossil fuels by scaling up the deployment of low carbon technologies;
- maintain security of electricity supply amidst an uncertain geopolitical outlook;
- continue to support the Contracts for Difference and Capacity Markets regimes to ensure a smooth transition away from remaining fossil fuel generation capacity; and
- allow consumers to take control of their own electricity use through enhanced price signalling, helping to address the rising cost of living.
2. The Case for Change
In 2013 the Electricity Market Reform (“EMR”) brought in Contracts for Difference (“CfDs”), the Capacity Market, carbon price support, and the emissions performance standard (“EPS”). However, it did not change the fundamentals of the “new electricity trading arrangements” established in 2001 (which were then extended to Scotland in 2005). In contrast, the proposals in the REMA Consultation represent a much deeper reform of our electricity markets, unmatched in scope since the 2001 reforms, and represents a tacit admission that EMR did not go far enough.
In BEIS’ view, the existing market arrangements and EMR have performed well, successfully delivering the first phase of power sector decarbonisation, but the challenges of the next stage will be different. To assess whether existing arrangements will remain fit for purpose, BEIS (in collaboration with Ofgem and National Grid Electricity System Operator (“NGESO”)) have identified five key challenges:
- increasing the pace and breadth of investment in generation capacity;
- increasing system flexibility;
- providing efficient locational signals to minimise system cost;
- retaining system operability; and
- managing price volatility.
All the modelled scenarios require a significant volume (around 300 GW) of new generation capacity. To fully decarbonise the power sector at the pace that BEIS requires, whilst meeting increased demand, between £280bn and £400bn of total public and private investment is needed.
Assessment of Future Market Arrangements
In particular, BEIS is seeking to address the following challenges:
The need for deployment of low carbon technologies (both on the supply and demand side) reducing fossil fuel dependence in the GB electricity market, whilst simultaneously meeting the rapidly growing demand for electricity generation.
The Energy Security Strategy announced in July 2022 called for:
- up to 50GW of offshore wind, including up to 5GW of floating offshore by 2030,
- a five-fold increase in the deployment of solar by 2035, and
- up to 24GW of nuclear by 2050.
Although the CfD scheme has been successful in delivering a substantial volume of low-cost renewable capacity through competitive auctions, a wider range of technologies will be needed to deliver the next phase of decarbonisation. Current arrangements will not suffice as renewables alone will not be enough to meet 2035 targets, and the Capacity Market is unlikely to bring forward low carbon flexible capacity at the required pace.
Security of Supply
Providing and maintaining a reliable supply and system resilience in the transition to a fully-decarbonised sector by 2035, by ensuring sufficient system flexibility to meet peak demand and incentivising low-carbon generators to provide operability services (for the purposes of system security) as well as energy output.
The Capacity Market was introduced to ensure that there is sufficient generation available to meet peak demand. However, the approach is likely to come at a risk of missing decarbonisation objectives because, as it stands, the Capacity Market continues to lock in higher carbon assets (like CCGTs and gas peaker plants).
BEIS seeks to ensure that reaching the above goals is cost-effective, provides value for money for consumers (by balancing financing costs and wider system costs), and ensures that the cost of system operation is minimised in order to reduce overall consumer bills.
Although the CfD scheme has been largely successful in reducing financing costs for renewable assets, and the Capacity Market auctions have secured over 10GW of new capacity from a range of technologies at low clearing prices, there have been a number of issues with current market arrangements, notably: a lack of locational investment and operational signals; limited temporal signals for flexibility; wholesale market prices broadly set by the most expensive plant (marginal pricing); and low wholesale market liquidity. BEIS has therefore concluded that current arrangements are not a least cost pathway to power sector decarbonisation.
There is a further challenge with timing, with it being estimated that, by 2027, existing or new support schemes could have locked in approximately a third of the capacity needed in 2035, and thus there is a need to consider long-term reform now so that reforms may be implemented in time to meet decarbonisation goals. Stability must be maintained in the market to deliver 2030 ambitions such as those in the Energy Security Strategy, whilst at the same time progressing reform that ensures we have markets that can successfully enable a low-carbon system in 2035.
3. BEIS’ approach to Consultation
BEIS proposes to proceed with REMA in the following three stages:
- setting out a statement of the case for reform (in the REMA Consultation);
- developing and determining what reforms are needed through engagement with energy sector (throughout 2022 and 2023); and
- establishing a delivery plan and overseeing implementation (from the mid-2020s) in time to meet the Government’s commitment of a net zero power sector by 2035.
BEIS is considering a broad range of options, including medium-term changes to existing arrangements that can be delivered from the mid-2020s, to longer-term transformational reforms, as well as changes which could be pursued on accelerated timelines and implemented regardless of the end package of reform.
BEIS’ discussion of options for reform are organised around core outcomes that the future power system will need to deliver:
- a net zero wholesale market;
- mass low carbon power;
- capacity adequacy; and
- operability (i.e. the provision of ancillary services for system security).
The applicability of each of the proposals for reform (set out at section 5 below) to each of the above outcomes is summarised by BEIS in the following graphic:
BEIS will assess options against the following five criteria:
- least cost;
- investor confidence;
- whole-system flexibility, and
Although a key part of the REMA programme will be considering how individual policy options relate to each other, BEIS does not propose to group individual options into coherent policy packages in the REMA Consultation. Instead, BEIS proposes to engage with stakeholders with the view to narrowing the field through consultation with industry and determining what reform is needed in 2023.
4. Cross-cutting Questions
BEIS has identified the following “cross-cutting questions” that it identifies as key to its overall approach to market reform. These are not policy questions that need to be specifically answered, but what BEIS considers as the key issues that need to be considered when evaluating the proposals that the REMA Consultation discusses.
- Role of the market - BEIS’ assessment is that market forces alone are currently unable to deliver the investment in the kinds of capacity needed to meet decarbonisation or security of supply targets. It expects that Government intervention will likely still be necessary.
- Competition between technologies - BEIS emphasises that the likelihood of finding the lowest cost solution increases with the variety of technologies competing in the power sector. To assure cost-effectiveness, BEIS’ general approach is to broaden the scope of cross-technology competition.
- Centralisation - although BEIS recognises the efficiency advantages of decentralised models of decision making, it believes some decisions should be made centrally, especially to account for social benefits that the market does not value.
- Marginal pricing - despite GB eventually relying less on gas, some low carbon technologies, such as power CCUS and hydrogen generation, will still be exposed to international commodity prices. To reduce GB’s exposure to global market developments, BEIS is exploring reforms that could move away from marginal pricing and towards a green power pool.
- Financing costs and operational signals - BEIS highlights a strong case for a market design that minimises investor risk (e.g. the CfD scheme). However, a lack of exposure to market signals limits the incentive for renewable assets to act more flexibly. BEIS is open to options to address this.
- The scale of change - BEIS recognises a growing misalignment between market arrangements and the core technologies which produce the power that is sold in the market. BEIS is exploring both “revolutionary” and “evolutionary” approaches to market reform.
- Electricity demand reduction - the design of energy efficiency and low carbon heating schemes and regulations is outside the scope of REMA. The REMA Consultation will consider whether and how electricity market design should further incentivise electricity demand reduction.
5. Proposed options for reform
At this stage, the proposals set out in the REMA Consultation are almost entirely theoretical, and are an exploration of the merits of different options. There is no statement of a unifying vision tying these proposed reforms together, nor is BEIS purporting to have one.
Despite this, some of the proposals (such as locational pricing and the division of the wholesale market) would be an enormous departure from the current structure of the GB market, and there are likely to be winners and losers from any implemented reforms.
This is a key point in time to engage with the proposed Government policy, and industry stakeholders should carefully consider the potential impacts of these policies on their business and their broader interests. In particular, BEIS is keen to ensure that investor confidence is not damaged, given the reliance of the proposals on private capital, and impact on investability is therefore an important part of assessing these options.
All industry participants will need to consider what provisions it may be appropriate to include in new contracts to deal with the potential impact of REMA, for example, change in law clauses and how existing long-term contracts might be affected, including industry contracts such as CfDs (which we would note already include principles-based provisions on updating their wholesale reference pricing for fundamental changes such as market splitting) as well as bilateral power purchase agreements.
We summarise below some of the proposals put forward in the REMA Consultation.
5.1 Net Zero Wholesale Market
Splitting the market by generation type
This proposal would divide the electricity market into separate markets for variable and firm power, with the aim of achieving a net zero wholesale market. The variable, “as available” market would include sources such as renewables, with the prices based on their long-run marginal cost. This would include all costs of producing a unit of energy, including building a new power plant, although how it was ensured pricing would fairly and accurately reflect these costs is not made clear. The firm, “on demand” market would include constantly available sources such as gas, with prices set by short-run marginal costs, mostly made up of fuel costs.
Splitting the market could decouple the electricity price from the global gas price. It would also provide incentives for demand-side flexibility, allowing consumers to benefit from lower variable market prices by shifting their demand.
Nevertheless, the Government recognises that this is an “untested, conceptual approach”. The questions that remain to be answered are whether all “as available” electricity would be consumed before the “on demand” electricity, how the costs would be recovered and how the responsibility for ensuring network operability would be managed. Further, it is unclear into which of the envisaged sections interconnectors and sources such as biomass would fit.
A variant of this option is the “alternative green power pool”. As part of this option, the system operator would manage a pool for renewable power, similar to a centrally co-ordinated power purchase agreement market. Renewable energy generators would sell their power into the pool at their long-run marginal cost (similar to a CfD) and consumers would purchase power from the pool at a lower price than the wholesale market price, but with higher variability.
As an alternative to national pricing of electricity (the current position), where a single national wholesale electricity price applies to the entire network, the Government proposes a shift to locational pricing. Tying location in with electricity prices could incentivise the generators to operate and locate their plants closer to centres of demand. This could be achieved through either nodal or zonal locational pricing:
- Under the nodal pricing model, the price at each transmission connection point represents a locational value of energy. This means that the physical constraints of the network are directly translated into the wholesale price. This system has been successful in some parts of the USA, New Zealand and Canada.
- Under the zonal pricing model, the market is split into zones and each zone has a single price – essentially a more granular version of the current single national price. This is the established model in the internal European energy market.
Whilst moving to locational pricing would alleviate some of the grid constraints, its impact on consumers would differ based on their location, depending on the relative amount of generation in the relevant zone or node.
Locational pricing would fundamentally change the economics of electricity generation projects, and we expect any proposals in this respect to generate strong opinions from stakeholders in the sector. For example, in a recent report NGESO, the electricity system operator, came out in favour of a “nodal location-based wholesale market with central dispatch” as its favoured option for reform. For more information on NGESO’s favoured approach to locational pricing please see our Law-Now on the subject.
Pay-as-bid vs pay-as-clear
The REMA Consultation includes the proposal to move the GB wholesale market to pay-as-bid rather than pay-as-clear pricing in delivering a net zero wholesale market. Under a pay-as-bid approach, participants receive the price of their bids/offers, as opposed the bid of the highest price generator (which is typically gas generation) selected to provide supply under pay-as-clear (known as “marginal pricing”). Although this has potential to decouple wholesale electricity prices from gas prices, and reduce wholesale electricity prices, if generators lower down the merit order were to bid below the current marginal price, it is vulnerable to participants “gaming” the system. This risk can be avoided by bringing in a limit on the price that individual technologies can bid into, resulting in a “cost-based” market design.
A move to a pay-as-bid system would require a fundamental change in the regulation of the wholesale market, which includes a move to central dispatch arrangements, as well as a mandatory power pool. It could reduce the incentive for flexibility because assets are paid based on their cost of production, as opposed to the value of an additional unit of electricity at a given time/location. It could also decrease the investment signal provided through wholesale market revenue as lower cost generators would not profit when higher cost generators set the price – this may require changes to investment support schemes to ensure generators were about to recover construction costs.
5.2 Mass Low-Carbon Power
Contracts for Difference
The proposed changes to CfDs are aimed at achieving mass low-carbon power, as well as improving the delivery of operability and ancillary services. At present, the CfD scheme is available to investors in low-carbon technologies, with the scheme being re-opened to solar and mainland onshore wind in the fourth allocation round. Auction winners benefit from a guaranteed “strike price” for every MWh generated, even when the market price is below (entitling them to a top-up) or above (requiring them to pay back into the scheme) the strike price, which provides revenue certainty. The auctions held to date have fallen short of incentivising developers to locate their projects in a way that is optimal for the network, and in facilitating competition with low-carbon flexible assets.
The REMA Consultation contains proposals for a CfD variant with increased exposure to the market price. Instead of difference payments being made on the basis of a single price, power plants would be guaranteed a maximum and minimum price per MWh output, with difference payments made only where the market reference price is above the maximum or below the minimum.
Similarly, under a CfD based on deemed generation model, generators would be paid on their potential to generate in a particular period, helping them avoid the need to export energy to receive the CfD top-up payment, as is currently the case.
The REMA Consultation also highlights that a number of renewable plant that currently receive CfD support are disincentivised from offering ancillary services due to losses in subsidy when diverting power from the wholesale market. It is the Government’s view that a majority of the flexibility-focused reforms (such as Capacity Market reforms, and a cap and floor for flexibility assets) would address this by exposing generators to market signals to incentivise flexibility between providing power and ancillary services to meet market demand.
One of the more controversial proposals aimed at achieving mass low-carbon power is an obligation on electricity suppliers to procure green electricity on behalf of their consumers. The Government would set an upper limit of carbon-intense electricity that suppliers can sell to consumers, and suppliers would contract with generators to meet this requirement.
For example, suppliers could be compelled to use low carbon electricity, or reduce demand, during times of peak demand, thereby maintaining system stability. However, this option may be introduced in conjunction with other options. For large-scale flexible assets with higher carbon intensity, for example, a supplier obligation may limit revenue generation, increase cost of capital, disincentivising investment.
Concerns have been raised in particular in relation to the proposed supplier obligation to procure renewable energy to consumers. Its opponents see the main barriers to mass uptake in low-carbon generation in planning and transmission infrastructure, rather than a lack of consumer demand for renewable power.
5.3 Flexibility and Capacity Adequacy
The Consultation contains the following proposals for Capacity Market reform:
- Specific auctions for flexibility – each auction would feature different response time and duration, potentially attracting more and different generation projects.
- Introduce multipliers to the clearing price – by creating a mechanism to reward specific flexibility needs (such as response time or duration) this would provide incentive to invest in flexible technologies. The location of flexibility assets could also be subject to multipliers, rewarding storage facilities proximal to areas of network constraint and treating these assets as more valuable.
Flexibility technologies eligible for multipliers will need to be subject to strict criteria (with scope for criteria to be adapted based on network requirements), for which there is no current consensus. Multiplier payments as part of the Capacity Market could be miscalibrated and introduce additional costs for consumers.
The Government anticipates that, as the electricity system becomes more reliant on intermittent generation, the Capacity Market needs to provide incentives for low carbon, flexible and firm power needed to complement this intermittent generation. One approach is an optimised Capacity Market which would involve changes to the current Capacity Market similar to the “specific auctions for flexibility” proposal set out above (with the key difference that optimised capacity market targets generators with low carbon or new build characteristics).
Two variations of the Capacity Market are under consideration:
- Separate auctions would involve running low carbon new build in a separate auction to the main auction with the ESO setting the total amount of capacity. It is anticipated that the clearing price would be higher than in a single auction.
- Multiple clearing prices would involve a single option but with different clearing prices set for each capacity type.
Revenue cap and floor for generators/ancillary service providers
The REMA Consultation proposes a revenue cap and floor model, under which generators would compete in the capacity, wholesale, balancing and ancillary services markets. They would be guaranteed a minimum revenue (the “floor”) by the Government in each period and would be topped up if they fail to meet it. They would also be limited to a maximum revenue (the “cap”), where a proportion of revenue above the “cap” is paid back into the scheme. This model has already been successful in incentivising development in the interconnector market, as well as being considered to support long-duration storage.
The REMA Consultation sets out proposals for a Strategic Reserve model. This involves auctioning a certain amount of reserve capacity above that which the market is expected to provide. Providers then receive a payment for being available and a separate activation payment. Capacity in strategic reserves is dispatched only where there is a danger that demand will outweigh supply and is at a price above reference level. Costs for activation are passed on to consumers through system charges.
Centralised Reliability Options
In a system with a centralised reliability option, the incentive to provide supply is signalled by the level of wholesale market pricing rather than targeting system stress events. The Transmission System Operator sets the amount of capacity auctioned at a level which meets peak demand and in return for a reliability premium, secures the right to buy electricity from generators on the wholesale market at “strike price”. This mechanism ensures availability of supply during scarcity by penalising contract holders who remain unavailable during the period in which real time prices exceed the “strike price”.
Several countries such as Ireland and Italy have operated a reliability option scheme and this option could address the issue of rising Capacity Market clearing prices due to declining load factors. This option is also compatible with the proposal for a split GB wholesale market (as discussed above).
Operability/Ancillary services for system security
The REMA Consultation covers the options proposed for delivering operability and ancillary services to NGESO. It outlines changes which could be made such as giving the ESO or FSO the ability to prioritise zero or low carbon procurement or giving carbon reductions equal weighting to cost effectiveness in procurement. Other proposed changes include ensuring ESO strikes the correct balance between long- and short-term contracts to optimise investment, aligning Capacity Market and CfD tenders with those for ancillary services and introducing a matrix approach to ancillary service provision so that providers can submit linked bids.
The REMA Consultation also proposes developing local ancillary services markets, including the procurement of ancillary services by DNOs at a local level. Ofgem are currently undertaking a review of Distribution System Operation governance assessing the key energy system functions at a local level and the effectiveness of institutional and governance arrangements in place to support their delivery.
Co-optimisation is also under consideration alongside broader wholesale market changes which involve central dispatch. This system is partly used in the US for frequency and reserve and involves co-optimising assets which provide generation and ancillary services by central dispatch with a view to more efficient allocation of generation and demand.
5.4 Options across multiple markets
Auctions by abatement
The REMA Consultation considers the SDE++ scheme used in the Netherlands, which focuses on large-scale rollout of technologies for renewable energy production and other carbon-reducing technology with technology-specific ceiling prices. There is a set budget for each auction and auctions are based on the cost effectiveness of each bid at avoiding CO2. Similar to CfDs, the Dutch government contracts directly with assets and provides subsidy for up to 15 years.
Equivalent Firm Power Auctions
The REMA Consultation also considers the option of an Equivalent Firm Power Auction (“EFP”). This is a single, technology-neutral, unified auction for procuring capacity and would be an evolution of the Capacity Market, integrating CfDs. Intermittent generation, flexible assets, and firm power generators would compete for capacity contracts based on “equivalent firm power”. This system recognises that intermittent generation introduces a cost to the overall energy system due to their variability and attempts to make intermittent generators internalise the cost of this variability by valuing equivalent firmness.
6. Next Steps
The REMA Consultation closes on 10 October 2022, and details of how to respond, as well as the full text of the consultation are available here.