The Hidden Risks of Regional Energy Pricing – Why Britain’s BESS Developers Should Take Notice

This summer, the Energy Secretary, Ed Miliband, has a big decision to make – whether or not to introduce zonal electricity pricing to the UK. This would see the end of a national electricity price, with the UK split up into different pricing zones and cheaper electricity prices for those living in areas with higher levels of generation.

The move is backed by the energy regulator, Ofgem, as well as the National Energy System Operator (NESO) and most vocally, Britain’s largest energy supplier, Octopus. If implemented, it will undoubtedly have significant implications for those developing and investing in renewable generation assets, such as battery energy storage systems (BESS).

At first glance, regional pricing may seem like an equitable approach to managing grid constraints and reflecting the true cost of electricity distribution. However, the reality is more complex and potentially problematic. The unintended consequences of this policy shift could have lasting adverse effects on the renewable energy landscape, investment confidence, and Britain’s overall transition towards a sustainable energy future.

Scotland exemplifies the challenges inherent in regional energy pricing. Blessed with substantial wind resources, Scotland currently experiences significant congestion issues due to its ability to generate large volumes of renewable energy that exceed local demand. The introduction of regional pricing could drastically diminish the attractiveness of battery storage projects in the region by significantly reducing their Internal Rate of Return (IRR). As a result, investors might become increasingly wary of committing capital to a market that promises lower returns and higher risks. This reluctance could stall essential renewable energy projects, undermining the Government’s clean power 2030 targets.

Northern England faces similar constraints, notably from the substantial offshore wind farms supplying the national grid. Offshore wind energy is a cornerstone of Britain’s renewable energy strategy, but regional pricing threatens to dampen investor enthusiasm. Structural constraints from the high north-to-south energy flow require substantial investments in grid infrastructure improvements and balancing solutions such as BESS. If regional pricing policies substantially reduce the economic viability of these projects, it could significantly hinder the deployment of new technologies designed to enhance grid stability and resilience.

Looking further south, the situation presents additional complexities. Alongside the significant congestion risks arising from numerous offshore wind grid connections, there are also the interconnectors that transfer power between the UK and mainland Europe to think about – although these are bi-directional flows, but only when power supply is needed and is requested.

These bottlenecks restrict the efficient distribution of electricity, resulting in potentially inflated regional pricing. Without carefully structured incentives or adjustments to regional pricing strategies, investors may reconsider their involvement, impacting the broader growth of renewable infrastructure.

The impact is not limited to renewables alone. Regions such as Southwest England, anticipating future congestion risks associated with exporting power from developments like Hinkley Point nuclear power station, might also experience investor hesitation. Even London, traditionally insulated from major energy distribution constraints due to high localised demand, faces potential issues as network constraints intensify with the continued growth of urban demand.

Regional energy pricing, intended as a tool to optimise efficiency and fairness, risks creating unintended regional disparities. Areas already burdened with infrastructure challenges might see exacerbated socio-economic divides, potentially resulting in higher energy costs for residents and businesses alike.

Given these significant implications, we’re urging policymakers and industry leaders to revisit and critically assess the implications of regional energy pricing. If the Secretary of State does decide that regional pricing is the way forward, rather than a blanket approach, targeted measures designed to encourage investment in constrained regions could provide more balanced outcomes.

Policymakers, developers, and stakeholders must collaborate to ensure the regional pricing model promotes rather than hampers Britain’s critical transition to a net-zero future. Only through careful and coordinated efforts can the UK achieve a sustainable energy framework capable of supporting robust economic growth, energy security, and environmental responsibility in the decades ahead.

The Clean Power 2030 target is to have 11GW BESS operational by 2030 across the UK on the distribution network

New research from leading UK independent power producer, Root-Power, has identified 7.6GW across 173 projects which will likely be made offers to connect pre-2030 now that reforms put forward by the National Energy System Operator (NESO) have been approved by OFGEM.

The Clean Power 2030 Action Plan (CP2030) target is to have 11GW BESS operational by 2030 across the UK on the distribution network. With around 3.4GW already operational, it is likely that 7.6GW in the pipeline will be made offers to connect pre-2030 once the reforms are implemented.

The reforms are part of the NESO’s plan to help the UK meet the Government’s target of clean power by 2030. The Clean Power 2030 Action Plan (CP2030) includes reforms to the grid connection process, infrastructure build and the planning and consenting process along with a reformed queue management process.

The proposal, now accepted by OFGEM, is to prioritise ready-to-build projects, however research completed by Root-Power demonstrates there is already far more than 7.6GW of fully consented BESS waiting to connect, with massive oversubscriptions meaning many fully consented, ready-to-build projects will miss out on a pre-2030 connection date, and many will also miss out on a pre-2035 connection date.

Root-Power’s queue analysis and research has identified the full list of 7.6GW of projects which it believes will make up this pre-2030 pipeline, the size of the projects, and who owns them. Root-Power is the only Independent Power Producer (IPP) on the list with more than 200MW due to the fall in merit.

Neil Brooks, Managing Director, Root-Power, said: “It is clear the market is heading for consolidation and there will be a need for developers to rapidly sell their project developments to IPPs who have the capabilities to finance and build them.

However projects due to connect before the end of 2026 have limited certainty around their connection date, this may impact the decision making when it comes to these acquisitions.

The CP2030 reforms will create great opportunities for the storage sector. However, once revised connection offers are issued, now likely to be early 2026, they will come with stringent commitment milestones, meaning developers who have limited means to deliver against these milestones must now look to divest of these developments.”

Root-Power’s research found:

There are 90 individual project owners across the 173 individual projects which make up the 7.6GW due to connect on the Distribution Network.
52 of the 90 project owners only have a single project in merit.
38 of the 173 projects (~1GW) are under 50MW in size.
Of the 90 project owners, around 65% are developers or consultancies and 35% are IPPs with in-house development capability.
Of the 7.6GW likely to receive pre-2030 offers, 4.4GW are owned by developers and only 2.8GW by IPPs.

In December 2023 NESO launched the Open Balancing Platform (OBP) – one of the primary objectives was to increase the utilisation of battery energy storage. The first stage of the OBP was enabling bulk dispatch of BMU assets, allowing hundreds of dispatch instructions to be sent at a single click of a button. This optimisation enables technologies like battery energy storage to play a more active role in balancing the network during imbalance periods. The OBP is expected to be completed by March 2027 (based on NESOs webinar, September 2024) and will fully replace the balancing mechanism as well as the ancillary services dispatch platform (the system used by NESO to procure operational reserves and contingencies)

The OBP will also be compatible with the new quick reserve service which launches in December 2024, with the auction commencing next month (mid-November 2024 at the time of writing) as the name implies, this is a service that requires fast response times, that is well suited for a battery, perhaps even only by batteries. In the fullness of time, NESO plans to further refine the OBP capabilities to create a fully comprehensive platform.

2025 will see constraint management support tools launch (although this isn’t anticipated to contain game-changing improvements for BESS), and new energy storage parameters (that are expected to have improvements for BESS) which should buck the trend of <15min dispatches for BESS. 15 minutes has typically been all NESO could see in the control room, and had no visibility beyond that without sending another 15min dispatch instruction and waiting for the BMU to report its Maximum Export Limit (MEL) and Maximum Import Limit (MIL), hence why they have been typically limited to <15min dispatches, with the new energy storage parameters this may shift more favourably towards longer dispatches for BESS.

Whilst this on paper sounds positive news for BESS, the skip rates remain high (over 90%) with NESO still favouring dispatching higher carbon assets. However, August saw the highest on record of dispatched volume for battery energy storage, 73GWh in fact (Source: Balancing Programme Webinar September 2024 PowerPoint Presentation (neso.energy)). More recently, batteries have been able to secure higher revenues remaining outside of the BM, however, batteries in OBP earned the highest revenues in the BM.

Batteries are more often being used for constraint management, where a constraint (for those non-power engineering) is a limitation on the amount of, or a minimum requirement for a parameter within the network (such constraints might be voltage, heat, frequency [stability]). When that limit is exceeded, it could result in a loss of supply or interruption. An example in simple terms, a transformer might be rated for 132kV, and without constraint management, the voltage through the transformer could exceed the maximum rating, leading to damage to the equipment, fires, or in the very worst case, a loss of life.

Constraints are not managed through the OBP, they use the legacy system (the predecessor to OBP) although NESO plans for this to move into OBP in time.

NESO published its plans for the OBP over the next 12 months, which will see several improvements to its services. October through December aims to see enhanced dynamic response and MWs dispatched, and updates to the legacy algorithm for the balancing mechanism. Q1 25/26 (Apr-Jun) may see the new storage parameters (this has been flagged as moving to a later date)

In conclusion the next 12 months should see improvements to NESOs services that will greater the impact that battery energy storage has [as the most flexible asset class at NESOs disposal] and overall energy markets, as well as improving the resilience for GB as we transition to a renewable grid.

Recently, UKPN hosted a webinar which outlined their proposed changes to grid connection applications, outlining the new ‘reforms’ they intend to put in place from the 1^st November 2024, driven by the Connections Action Plan from Ofgem in 2023. The new requirements for developers are as follows:

Must provide a Red Line Boundary, a detailed site layout plan including asset location, a detailed engineering design plan (new requirements) and a Single Line Diagram for the project (existing requirement).
Must provide a Letter of Authority with Exclusivity to the land with a 36 month option (enhanced requirements).
Must provide a project plan including main stages of the project, key milestones, target dates for connection and commissioning, in-depth studies, planning dates, lead times and construction dates (new requirement).
Must provide Part 4 of SAF application form (new requirement).

As Developers, it is disappointing that it appears the only consultation that was done on this reform to the connection application process is with ENA and the Connections Process advisory group. Considering only a small group of developers form part of this group, we would have expected that a lot more effort is put in by the DNOs to engage with developers considering this change will mostly affect them, prior to its implementation in November to ensure requirements are realistic.

Root-Power have approached UKPN and other DNOs, as well as the ENA, to try understand this new policy in more detail prior to its implementation. So far we haven’t had any responses. Our main takeaways so far are as follows:

Although increasing the application requirements is a step in the right direction which will hopefully reduce the number of developers which submit applications for speculative projects which are clogging up the connections queue, more focus needs to be done on managing the existing connections queue and reducing and managing the over-saturation which is already existent in the grid network.
DNOs need to ensure these requirements are realistic and we are disappointed that more effort wasn’t made by DNO’s to consult Developers before implementing this change. For example, requirements for detailed engineering plans, designs, and programmes are not realistic even for many experienced developers, as at the application stages many of these details will not yet have finalised or agreed. To expect this work to be done at such an early stage of the development process, prior to getting confirmation from the DNO themselves that a connection is viable in the specified area is timely and wasteful for developers.
If this is expected pre-application, then a lot more work needs to be done from the DNO side to ensure data on the status and capacity of their substations is publicly available, up to date, and accurate. Although heat maps for DNOs are readily available, these are generally outdated and inaccurate, and rarely reflect the outcome of the grid offer. DNOs need to allocate the resource to provide in depth pre-application grid support and information.
As developers, we have not had any communication directly from UKPN, or any other DNOs, informing us of this change other than a slide in the UKPN webinar. Across the board, more effort needs to be taken to keep Developers up to date with these changes and reforms.
These ENA changes need to be joined up with and aligned with the ongoing ESO reforms. We’re generally supportive of increased application requirements however these need to be realistic and discussed with Developers at consultation prior to their implementation.

We expect:

ENA must commit to publishing a public consultation on these changes before they are implemented in November.
Resource to be committed to ensuring up to date publicly accessible grid network data for Developers.
More clear alignment with ongoing reforms.
A focus from DNOs on delivering projects with planning permission and land rights.

Open letter on the reformed regulatory framework on connections (ofgem.gov.uk)