Does the Clean Power Plan for 2030 spell the end of the zonal pricing debate?

The Clean Power Plan entails a massive increase in capital investment, plus the ability to harness all types of flexibility 

Last week the National Electricity System Operator (NESO) published its pathway analysis to achieve a clean power system by 2030. The Clean Power Plan marks a significant milestone and a shift in thinking about how we will deliver a decarbonised GB electricity system. Combined with connection reform, it seeks to align infrastructure investment with the deployment of new generation, storage and flexibility.  

The pathways rely on three key elements:  

1. A massive increase in renewable energy generation, especially offshore wind, onshore wind and solar 
2. Aligned network investment with at least an additional three major transmission projects in the South East   
3. A big uptick in flexibility from storage (27-35 GW), interconnection(12.5 GW) and demand response (10-12 GW). 

In total, NESO has calculated that the new capital investment needed will be about £40-50bn per year over the five-year period to 2030, of which £31-34bn is generation and storage.  

The network investment has been identified in the Pathway to 2030, with additional projects brought forward from the Beyond 2030 investment plan. NESO appears to be quite bullish that these projects can be built by 2030 or shortly after, with the key caveat around planning.  

Stating the obvious, for a given level of generation and interconnectors built, the level of network investment delivered directly impacts constraint costs. This is set out in the report, with falling levels of constraint costs with each additional round of network investment. Significantly the three critical additional projects NESO has identified are in the south east of England, linking East Anglia to Kent and Norwich to Tilbury. As LCP Delta has also identified in its recent report, Exploring Zonal Pricing In Britain, this marks a shift in focus towards southern constraints, particularly the SC1 transmission boundary constraints which are related to new interconnector flows rather than wind generation. 

The investment in renewables is eye-watering. It includes a leap from 15 GW to 45-50 GW of offshore wind, a doubling of onshore wind to 27 GW, and a trebling of solar to 47 GW. Whether these levels of generation capacity can be delivered in five years is undoubtedly one of the Clean Power 2030 challenges. As the report highlights, a lot is now resting on the two forthcoming CfD allocation rounds (7 and 8) to deliver a very significant uplift in contracts awarded.  

If increasing generation is the first challenge, it is closely followed by another: increasing battery storage to circa 22-27 GW and long duration storage (LDES) to 4-8 GW. As the report acknowledges, there is a big storage pipeline, especially for shorter lead-time battery projects, but the key to unlocking storage is to ensure that there is a viable market for storage services and, where necessary, appropriate revenue support via the Capacity Market and a cap and floor scheme. Demand-side flexibility also has a big role to play, as we will discuss later.   

So, what does this mean for the zonal pricing debate? 

The Clean Power Plan states that, in NESO’s view, “a locational pricing model is likely the best way of mitigating the risks and maximising the opportunities of a decentralised power sector”. However it goes on to highlight the need to provide “stability and confidence” to investors and to proceed with the reforms to the CfD scheme and Capacity Market.  

Elsewhere, the report acknowledges that its stakeholder engagement provided “a variety of views on the benefits of fundamental reform to the wholesale market arrangements to move away from the national pricing model to a more granular level, e.g. through zonal pricing”. And that “many market participants considered that the introduction of significant reforms to market arrangements could create sufficient uncertainty to risk delivery of the technology pathways identified in this report, at best increasing the required cost of capital to deliver the investment and, at worst, stymieing the investment completely”.   

So, while NESO is maintaining its pro-zonal stance, nothing in the report suggests a full-throated call for radical market redesign as a prerequisite to clean power delivery. Below I set out four reasons why the government should call time on the zonal pricing debate and quickly move forward with ambitious but progressive market reform.

1. Timing is now critical 

The government has indicated that it intends to respond to the NESO’s Clean Power Plan, setting out its response and delivery plan, before Christmas. Urgency is needed because there are pending decisions on the next CfD allocation round, cap and floor support for interconnectors and long-duration storage, and decisions that need to be made about Sizewell C – plus a whole bunch of network investments and market reforms to be getting on with.  

It would be counter-productive for the government to launch its Clean Power Mission to mobilise £40bn of annual investment while the fundamental elements of the future electricity market design are still uncertain. A decision on the direction of market reform is needed before or as part of the Clean Power Plan announcement in December. 

We do not have a clear zonal market design ready to adopt. 

To make a decision to opt for zonal pricing, the government needs to know the basics of the end design so it can assess its impact. A rash decision for zonal without key elements of a design would not bring “stability and confidence” to the industry and investors, but would instead introduce a further long period of policy uncertainty, rancorous debate and implementation risk.  

The challenge, however, is that we are still a long way from having a clearly defined multi-zonal market design. Stakeholders are still waiting for a response to the 2nd REMA consultation, which ended in May, and no practical design has yet been defined and presented to stakeholders.1   

Big questions remain to be answered. For example:  

• Would the zonal market allow the GB market to continue to benefit from a decentralised market with bilateral trading, forward markets and the use of PPAs, or would it require a return to a predominantly centralised market and central dispatch?
• Would demand be exposed to zonal pricing, and what methods of shielding disadvantaged consumers would be used? How would consumers be protected in this new market with a potential loss of price competition?
• How would the cross-zonal and intra-zonal distributional issues be addressed? 
• How would the 7,500 smaller distribution-connected assets be impacted, and how would they be allowed access to the market? How would generators who have paid for their network connection upgrades be compensated?  
• What would be the method and process for cross-zonal trading and hedging? 
• Would balancing be required at a zonal level? Would it be practical? 
• Would multi-zonal markets be viable and competitive, or lead to price gouging? 
• Would small, illiquid zones default to a centralised market killing off PPAs and bilateral trades? 
• How would the CfD and other support schemes be impacted? Would CfDs need to be deemed and, if not, what would be the negative price rules? 
• How would zonal pricing impact retail market reform? 
• How would existing connection agreement holders be treated? Would they be compensated, and where would constraint risks now sit? 

The cost of operating a zonal system, with likely transactional, commercial and operational friction leading to market inefficiency, has not been quantified. Any proposals would also have to be accompanied by a comprehensive set of proposals to mitigate investment risk and provide some degree of compensation to existing market participants for the loss of their connection rights. This is likely to be challenged. 

Addressing these questions would require several more months of design work and stakeholder engagement and, at a minimum, another round of consultation. We do not think that policymakers are yet in a position to make a decision in favour of zonal based on the evidence and analysis that has been undertaken. 

2. Having a plan aligned with grid investment removes a key argument for locational marginal pricing within the wholesale market 

The existence of a Clean Power Plan, with the spatial allocation of generation capacity that is aligned with investment in grid infrastructure and a new connection policy, removes one of the main arguments for locational marginal pricing. This is a fundamental change to the way energy systems are built, moving away from a developer-led ‘connect and manage’ approach towards a more coordinated and planned approach. The Clean Power Plan takes a big chunk out of the zonal benefit case, a point that LCP Delta has also made in its updated benefit analysis of Zonal Pricing in Great Britain.  

There was always scepticism about the ability of marginal prices to give positive long-term investment signals, but if generation and network capacity are aligned to an overarching plan and directly linked to that plan via connection reforms, the need for locational price signals is greatly reduced, if not removed. Further, more granular investment signals that may be needed could be given via: 

• Network charging or, more directly, via regional energy system planning (RESP), leasing and planning permissions
• Locational signals that are already present in flexibility contracts, constraint management zones and in the Balancing Mechanism (BM)
• Adding a locational element to the way in which CfDs, cap and floor and Regulated Asset Base revenue support contracts are awarded
• Having a joined-up industrial strategy for the generation and use of energy based around industrial clusters, green power pools and regional development areas. 

The options for providing effective locational investment signals are discussed in more detail in our paper Progressive Market Reform for a Clean Power System.  

We would argue that all benefits related to generation, storage and interconnector siting decisions should be discounted from the zonal benefit case modelling. 

Discounting locational siting signal benefits is not the end of the zonal story. The debate has moved on to consider whether zonal pricing would provide better operational signals. There are several aspects to this, but the two key operational issues which have come to the fore are: 

1. Interconnector flows and whether a zonal price would ensure that interconnector flows would support and not exacerbate GB constraints. This is important.
2. Whether a zonal market would provide stronger and more effective price signals for demand response, allowing demand to flex to both alleviate constraints and make better use of constrained renewable energy.    

3. Reforming interconnector flows is part of a wider cross-border trading issue. It needs to be fixed, and there are opportunities to do this through collaboration with EU partners. 

The interconnector argument for zonal has some merit. It’s a problem if GB is importing electricity into a zone that is already constrained, or potentially exporting from a short-balanced zone, because traders are responding to a national price signal.  

Interconnector operational efficiencies are now the key quantified system benefits behind the case for zonal pricing, amounting to between £0 and £8bn over 20 years in the LCP Delta system benefit study for DESNZ and between £0 and £11bn over 20 years in the more recent Zonal Pricing in Great Britain study. The large range of benefits depends on the counterfactual and whether interconnectors can provide dispatch flexibility. It also depends on which interconnectors are included in the model assumptions – a variable that has not been transparent. 

This is a complex area and is, to some extent, tied up with the fact that the GB post-Brexit cross-border trading arrangements are themselves inefficient and not fit for purpose. This has been highlighted by various industry groups and forums concerning the need for a) a recoupling of GB interconnector trading arrangements, b) harmonisation of emissions trading and the introduction of the Carbon Border Adjustment Mechanism, and c) better coordination of interconnector and Multi-Purpose Interconnector cross-regional planning and operations, especially across the North Sea and Irish markets.   

This cross-border trade context is important because anything that UK policymakers wish to do to control interconnector flows, whether through the introduction of zonal pricing or changes within the existing market arrangements, will require cooperation with our EU partners. 

Regen has argued that the broader interconnector issue is urgent; it is already costing consumers billions, and we cannot wait five years until the completion of future market reform to address it.  We have also argued that, as part of the broader reform to GB-EU interconnector arrangements, there is an opportunity to address the issue of interconnector flows and their impact on constraint costs by a) better alignment of the timing of interconnector trading and scheduling with GB market trading, b) allowing for standardised intra-day trading on all GB interconnectors, and c) putting in place cost-efficient mechanisms for SO-SO trading, capacity setting and coordinated re-dispatch/balancing. 

The benefits that could be gained without going down a zonal pricing route are significant. The Delta/LCP analysis suggests that even just an ability to redispatch 25% of interconnector capacity would reduce the zonal benefit case from just under £11bn to less than £3bn over 20 years.  

“Reforming the national market to enable the redispatch of just a small proportion of interconnector capacity reduces the system benefits of zonal pricing by £8bn.”
– LCP Delta, Zonal Pricing in Great Britain 

The Regen paper on Progressive Market Reform discusses the reforms needed to allow better interconnector dispatch, but they need to be worked through in detail. There may be other options, but there are four immediate reform avenues to explore. They include: 

• Better interconnector planning and integration within the overall Strategic and Spatial Energy Plan and network investment planning. The first thing to get right is to put interconnectors in the right place and align them with grid investment plans. See, for example, the SC1 boundary constraints and “Kent bottleneck” alleviation, which is estimated by NESO to save £4 billion.2 
• Standardising the use of capacity limit setting: Allowing the system operators, by agreement, to set capacity limits ahead of trading in anticipation of constraints, energy security and/or other system balancing issues. This will have a cost to interconnector operators, which would need to be addressed either by compensation or within the cap and floor support scheme. Note: at present, some degree of capacity limit setting is in place on some interconnectors, but this is mainly a security of supply mechanism. 
• Enhancing SO counter trading: A review of how the NESO trades directly with interconnector counterparties and whether these transactions are cost-effective and competitive. Also, consider the process and timing of counter-trading windows vis-à-vis market trading and dispatch. 
• Enabling SOs to create mutually beneficial balancing arrangements. Sometimes confusingly referred to as SO-SO trading, it is better described as a ‘collaborative SO-SO cross-market balancing arrangement’, whereby the import SO asks the export SO to include its constraint volume within its balancing mechanism and provide a bid price to turn down generation.3 If the generator bid price is cost competitive with domestic generator turn-down or demand side response (DSR), as it may well be if the export market is running gas or coal plants, it may be accepted. This is similar to a scheme currently under development between the German and Danish system operators to extend the pool of available balancing assets into the neighbouring market. 

Developing these options will require resources and time. It will also require NESO and policymakers to engage with neighbouring markets, which is why we think that this needs to be part of a wider push for collaboration and harmonisation of energy and carbon trading arrangements. This will be a negotiation challenge, but it is also an opportunity to show that the UK has moved on from Brexit and is working towards a closer economic partnership with Europe, with energy leading the way. 

It should be noted, however, that even if GB went for a zonal pricing model, this would impact cross-border arrangements and would require negotiation and agreement with our Northern Ireland and our EU partners.  

A zonal model would also offer an imperfect solution and would still require NESO to be able to redispatch interconnector flows cost-effectively. The zonal pricing solution for interconnector flows has been presented using modelling with perfect foresight. In reality, a zonal price, set at the day-ahead time when interconnectors are scheduled, will often not be able to predict the occurrence of next-day constraints. Constraint forecast inaccuracy will be exacerbated by the binary nature of zonal pricing in high renewable energy zones, which will oscillate between zero or negative prices and a high price set by the highest-cost generator, leading to periods when the zonal price import/export signal is wrong. So the NESO will still need to be able to redispatch interconnectors efficiently. 

Regen and others have recommended that the government urgently establish an interconnector task force to review cross-border trading arrangements and engage with EU partners. This should be a key element of the Clean Power Mission. 

4. A zonal market is not the best way to engage demand side response; there are better options within a decentralised national market 

The case for zonal pricing has shifted towards the demand side impact and the argument that more granular and sharper price signals are needed to engage consumers and elicit effective demand response. In particular, it has been argued that demand turn-up in constrained areas in Scotland is needed both to alleviate constraints and to soak up abundant renewable energy when the wind is blowing. 

Putting aside concerns that this case has misleadingly been presented as a low-cost energy bonanza for Scotland,4 and the distributional issues this would create within Scotland and between consumers in constrained and non-constrained zones,5 there is an important underlying point that we do need to engage DSR. The Clean Power Plan high flex pathway proposed by NESO includes almost 12 GW of demand flexibility reduction during peak periods from, for example, domestic appliances, commercial and industrial demand, and EV charging. That is a lot of demand reduction.  

It is incorrect, however, to say that zonal pricing is the only route to engage consumers and incentivise demand response. In fact, if zonal pricing ends up as a more centralised and predominantly day-ahead market design, it would provide a very ineffective flexibility market solution. 

There are several other market routes to achieve a high flexibility outcome, some of which are in place today and some of which could be greatly enhanced. It is, however, a fair question to ask whether the existing market solutions are working effectively and whether there is a sufficient and agile short-term market to fully mobilise flexibility services. This question should be a priority focus for REMA. 

Regen’s view, as set out in the Progressive Market Reform paper, is that we should approach demand side flexibility on two fronts: 

1. Agile wholesale prices (day-ahead, intra-day and short-term market trading and within the BM) that reflect the overall supply-demand balance, shifting broad swathes of demand away from peak demand periods and into periods when there is lower demand or excess generation. These power prices should then be reflected in competitive agile-use tariffs, available to all consumers and enabled through smart appliances, smart charging and applications. We could think of this as shifting the baseload of demand. Importantly, this needs to be done without losing demand diversity by prompting such sharp temporal and locationally specific demand responses that would create constraints on lower voltage network infrastructure.  
2. Targeted distributed flexibility services to meet system requirements for balancing and constraint management and to provide operational resilience. Sometimes referred to as ‘explicit’ flexibility services, they can be procured and instigated through several flexibility market solutions, including:
   1. • An expanded, efficient and competitive BM as the main route to market for flexible DSR services. It is positive that NESO’s Clean Power Plan has highlighted the role of the BM and the need for enhanced digitalisation and control room automation, restating the NESO commitment to address the issue of ‘skip rates’. Progress to enhance the BM is being made, but we think that reforms could go further and faster, turning the BM into a genuine dynamic spot market and adding energy usage optimisation (‘use it, don’t curtail it’) alongside dispatch efficiency as key BM outcomes.  
      • Contracted flexibility services, which are already widely used on the distribution networks and procured over 2 GW of flexibility for constraint management in 2023. 
      • Local constraint or local flexibility markets, which would allow NESO to procure flexibility services, including DSR, ahead of or alongside the main BM to enable earlier scheduling and an additional opportunity for price competition.  
      • Intertrip services, active network management and several other technical solutions that can also be implemented to enable greater capacity utilisation. 

A key aspect of flexibility services is that they can be targeted to provide a specific response at a specific time and location. They do, however, require market development, facilitation and coordination. Coordination is especially needed between network voltages so that the flexibility markets avoid giving contradictory signals that might exacerbate constraints elsewhere on the network. Elexon, as a market facilitator for distributed flexibility, has a critical role to work with the NESO, transmission operators, distribution system operators and Ofgem to develop these market solutions.  

More detail on how DSR and distributed flexibility services can provide system value are included in Regen’s Progressive Market Reform paper and in Energy System Catapult’s recent publication Enabling Distributed Flexibility for Net Zero. 

In conclusion  

The government should decide on the direction of market reform (REMA) before or alongside the publication of its Clean Power Plan, which is slated for December 2024.  

This is not consistent with a decision to go for zonal pricing, which, in the absence of a clear market design, would require months more design work and at least one further round of industry consultation. This would add to investment uncertainty and risk at a time when we need to secure £40bn of investment per annum to deliver a Clean Power system. 

Meanwhile, the benefits case for zonal pricing has been further challenged by the shift towards a more strategically planned energy system and connection reform, which has largely replaced the need for locational siting signals. The remaining areas of benefit, which relate mainly to the operation of interconnectors and enabling demand side response, cannot wait until the future implementation of zonal pricing and can be more effectively achieved through a progressive market reform programme.  

The conclusion, therefore, is that the government must call time on the ongoing zonal pricing debate and quickly move forward with ambitious but progressive market reform that can be delivered within the existing decentralised national market arrangements.