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问题卡生成于 2026/11/4 07:14:01
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问题依据 · 5
E1·European Commission CORDIS·采集/快照 2026/8/10
Periodic Reporting for period 1 - SPOCEI (Smart Planning, Operation and Control for Energy Internet)
101023244 projectId: 101023244 periodFrom: 2022-01-19 periodTo: 2024-01-18 workPerformed: Work was conducted via 6 work packages (WPs)WP1 refers to the project management. The researcher managed the whole project and reported the process to the supervisor through two-weekly meeting, determining on all aspects of the project. WP2 refers to the training and career development. The researcher performed diverse actions: 1) wrote a mandatory professional development plan following the requirement of University of Oslo; 2) talked with Vice Head of Department at Department of Informatics about the future plan; 3) lectured “Deep Reinforcement Learning for Demand Response and Energy Management” in University of Oslo to increase the lecturing experience; 4) helped to supervise 2 PhD students to improve the supervised ability. With those effort, the researcher promotes to the Assistant Professor and will join in Aalborg University after the fellowship is ended.WP3 refers to the research on controllable structure planning. We have established typical structures and proposed structure planning method by designing a mixed maximum matching and deep deterministic policy gradient method. Research studies yielded one conference paper that receives the Best Paper Award from 2023 ICCSIE. WP4 refers to the research on distributed and adaptive control strategies. We have proposed the data-driven load forecasting method, and several distributed and adaptive control strategies, which enables energy internet to obtain the optimal control operation without requiring systems’ dynamics and models. Research studies yielded 2 journal publications, with additional one magazine and one journal papers under review. WP5 refers to research on distributed power trading mechanism. We have established several energy trading models and designed diverse distributed algorithms to achieve multiple timescale energy trading. Research studies yielded 2 journal publications, with additional two journal papers under review. With the achievements in research, the researcher received the 2023 Excellent Young Expert Award from journal of Modern Power Systems and Clean Energy (MPCE). WP6 refers to dissemination and communication. The researcher performed diverse actions: 1) gave tutorials at the 11th ISGT-Asia, and invited talk at CAA Youth e-Summit and three universities; 2) co-organized one special section at the 4th SPIES, one track at the 33th ISIE 2024, one workshop at the 15th SmartGridComm, and one on-line seminar; 3) served as the guest editors of IET Electronics Letter and Frontiers in Energy Research, served as reviewers for several journals, and received the 2023 Excellent Reviewer Award from MPCE. ; 4) served as the Student Video / PHD Thesis Competition Chair of the 15th SmartGridComm; 5) attended a lot of seminars organized by University of Oslo. finalResults: This MSCA project has advanced energy internet planning, operation, and control in three main areas:1. Structure Planning: In WP3, we discovered that loss of controllability is a key factor in energy internet cascading failures. Our new structure planning model, integrating network controllability and economic operation, is pioneering in using a controllability index for this purpose. This model has the potential to significantly reduce the risk of large-scale failures.2. Control Strategy: WP 4 introduced novel distributed and adaptive control strategies for the energy internet. Compared with the existing studies, the proposed methods, fully distributed and not requiring expert knowledge or system models, are particularly effective for energy networks with high renewable energy penetration. This achievement has the potential to accelerate the digital decision-making.3. Trading Mechanism. In WP5, we presented unique distribute optimization methods to achieve the optimal energy generation/consumption and optimal energy flow allocation. Compared with the existing studies, our proposed methods can simultaneously hold the features of initialization-free, distributed implementation, asynchronous communication, and strong robustness to cyberattacks. In addition, we also established the theory foundation. With this effort, this project generated new distributed power trading method and theory to solve a class of new distributed optimization problem.The outputs of the project possess good potential impacts, since our research are capable of contributing to two UN Sustainable Development Goals (SDGs): 1) Affordable and Clean Energy (SDG 7); 2) Climate Action (SDG 11). Specifically, we developed distributed and mode-free control method to deal with the uncertainty of the renewable energy and enhance the system adaptivity. Meanwhile, we designed distributed trading mechanisms that are beneficial for the local utilization and integration of renewable energy sources. Thus, the outputs of the project provide potential solutions to increase substantially the share of renewable energy in the global energy mix. It fits well with the 2th targets of SDG 7. Moreover, we opened up new method to reconfigure the energy internet from the concept of controllability view against system cascading failure. Thus, it can effectively strengthen resilience and adaptive capacity to climate-related hazards and natural disasters, which fits well with the 1th target of SDG 11.
E1·UK Department for Energy Security and Net Zero·采集/快照 2026/8/12
UK community and grid-scale battery safety evidence
4. Ensuring safety 4.1 Introduction to battery safety risks 4.2 Grid-scale batteries 4.3 Domestic batteries 4.4 Community batteries 5.1 Australia 5.2 Europe 5.3 UK Lithium-ion batteries have become part of everyday life, from phones and laptops through e-bikes and electric cars to the standalone home and community storage units on which this document focuses. For most people, use of lithium-ion batteries is without incident, but they do carry a risk of fire, particularly if improperly built or installed. That risk does not mean that batteries cannot be used safely – after all, most UK homes contain gas boilers, which similarly pose significant risks if poorly installed or maintained – but does mean that, as for gas boilers, it is important that safety is taken seriously, particularly in design and installation. This section provides an overview of the inherent safety risks associated with battery technologies and the existing regulatory and standards frameworks that apply across domestic and grid‑scale storage. We are seeking views on whether these frameworks remain appropriate and proportionate for community batteries as deployment increases, and whether any gaps in standards, responsibilities, or risk management need to be addressed. Like many modern appliances, from boilers to mobile phones, the components used in batteries have the potential to cause harm, and so it is important that in their manufacture, installation and use, consideration is given as to how most effectively to mitigate that harm. Domestic and grid-scale batteries mainly use lithium‑ion chemistries, with some sodium‑ion systems emerging. Lithium‑ion and sodium‑ion cells hold large amounts of chemical energy in a compact structure. Cells are packaged into modules and packs, controlled by a Battery Management System (BMS) to keep voltage, temperature, and current within safe limits. This energy is normally stable as long as the separator keeps electrodes apart and the BMS regulates charging and temperature. Fire incidents involving lithium‑ion batteries used in mobile applications - such as e‑bikes and e‑scooters, particularly when unlawfully retrofitted - have been documented. However, there is no evidence to suggest that fire incidents involving professionally installed domestic battery storage systems are a common occurrence. These systems are substantial, stationary units that are subject to established regulatory requirements and technical standards that apply to battery manufacture, installation, and operation. Nevertheless, risks may arise where systems are not correctly installed. Community batteries are expected to meet the same baseline safety expectations as other energy storage assets. The overview below therefore provides context for considering whether existing frameworks remain appropriate and proportionate as the sector grows. This document focuses on community batteries, but it is contextually useful to outline the safety regime that exists for larger batteries connected directly to transmission and distribution networks. While fires have occurred at battery sites in Great Britain, they are rare. Fires at grid-scale battery sites are less frequent than those at non-domestic buildings from all sources. The latest available 5-year annual average fire incidence rate for grid-scale batteries is 0.7% (2020/21 to 2024/25),[footnote 11] lower than non-domestic building fires in England at 0.8% (2020/21 to 2024/25).[footnote 12] This risk is mitigated by a robust regulatory framework overseen by the Health and Safety Executive (HSE). This framework requires responsible parties to take measures to ensure health and safety throughout all stages of a battery system’s deployment. It is important that those involved in the deployment of BESS sites are aware of their legal duties. HSE supports this with guidance on its website. Where health and safety standards are concerned, best practice is reflected in common international standards such as National Fire Protection Association’s NFPA 855 Standard for the Installation of Stationary Energy Storage Systems , as well as Underwriters Laboratories’ UL9540A Test Method for Battery Energy Storage Systems (BESS) which is the critical test method for thermal runaway propagation. American standards, such as those developed by NFPA and UL, are normally applied to BESS projects in the UK as there are no currently developed UK or EU equivalent standards. These American standards are recognised globally and the UK insurance industry typically mandates them as a requirement of its insurance agreements. The government works closely with the Electricity Storage Health and Safety Governance Group, whose members include the Health and Safety Executive (HSE), National Fire Chiefs Council, and the Environment Agency. The Governance Group is responsible for ensuring that an appropriate, robust and future-proofed health and safety framework is sustained. As part of this work, the Group has developed and published health and safety guidance for grid-scale batteries. The guidance aims to improve the navigability of existing standards and provide a clearer understanding of relevant H&S standards. The government, through the industry-led Electricity Storage Health and Safety Governance Group, will continue to monitor the sector closely. In August 2025, DEFRA launched a consultation on including grid-scale batteries within the Environmental Permitting Regulations, to provide further safeguards and assurance. DEFRA is currently analysing feedback to this consultation and will publish a government response in due course. For domestic battery storage systems, as with any electrical appliance, there is an inherent risk of fire which cannot be completely eliminated. As for other household appliances, government sets safety standards, but individuals and property owners are best placed to make informed decisions about installation and use, supported by certified installers, product information and the specific characteristics of their property. A range of UK regulations and standards significantly reduce risk and ensure safe installation and operation: In addition to the regulatory and standards framework set out above, the government previously commissioned a detailed review of the safety risks associated with domestic lithium-ion battery energy storage systems in 2020. This review, carried out for the Office for Product Safety and Standards (OPSS) and the then Department for Business, Energy & Industrial Strategy (BEIS), examined the operation of domestic battery systems, known incident data, potential failure modes (including thermal runaway), and the effectiveness of existing and emerging mitigation measures. The review also provides an overview of relevant safety standards and codes of practice. Community batteries differ significantly from domestic batteries, in size, location and ownership. They typically have higher total power, energy capacity and voltage, serve multiple households or businesses, and may be installed in shared or public spaces where access and emergency planning needs careful thought. They can also involve varied ownership and maintenance models, which means responsibilities for ongoing safety checks must be clear. While these characteristics do not in themselves indicate a higher level of risk, they do create a different risk profile compared to domestic batteries and raise important questions about whether standards designed for small-scale, single-property installations are sufficient for community-scale projects. For example, PAS 63100 excludes dwellings over 200 m², and MIS 3012 only applies to systems below 50kW. We have identified community batteries in the UK that fall outside the scope of both standards. We want to understand what gaps exist, whether these gaps pose any risks, and what additional measures might be needed. Current and prospective community battery users, as well as relevant local authorities (including fire services), are invited to share views on the following: As noted, community battery projects are already operating in the UK, and we are keen to highlight some examples. Similar initiatives are emerging internationally, particularly in Australia, offering valuable lessons for UK. We are keen to share these insights while also learning from projects developed here at home. One prominent example is Australia’s ‘Community Batteries for Household Solar’ programme, supported by A$200m in federal funding. This initiative aims to deploy around 400 community battery systems nationwide, enabling communities to store excess rooftop solar energy and access affordable power. The programme has attracted significant attention. In June 2024, the Australian Renewable Energy Agency’s (ARENA) awarded A$124.7m in Round 1 to fund 318 batteries ranging from 50kW to 5MW. The application round for Round 2, offering A$46.3m, closed in September 2025. The Department of Industry, Science and Resources is separately administering A$29m of the available grant funding.[footnote 14] This approach has been particularly effective in Australia because high levels of domestic solar generation means that distribution networks are often constrained by excess daytime exports, as large volumes of surplus solar generation flow back into the grid simultaneously. This can lead to grid congestion and force distribution network operators to impose export limits. Community batteries are therefore strategically installed within local distribution networks to store surplus solar energy generated during the day before it reaches the wider grid and release it during peak demand periods. This model benefits both solar and non-solar households: participants can rent storage capacity, earn credits for stored energy, and enjoy lower bills. However, like all retrofit virtual private networks, consumers must switch to a specific supplier to benefit. While uptake has been strong in engaged suburban areas, there have been some challenges in onboarding more vulnerable households. We are keen to explore whether this model, or similar approaches, could be adapted for the UK to deliver benefits such as bill savings for low-income households. PowerBank Community Battery pilot, Western Australia – type 3 virtual private network[footnote 15] Context: PowerBank was a joint pilot by Synergy and Western Power exploring the potential of community‑scale batteries to support Western Australia’s South West Interconnected System (SWIS). Delivered across 12 metropolitan and regional locations, it was the first pilot in Australia to integrate a utility‑scale battery into an existing major metropolitan electricity network for the purpose of providing virtual storage to individual customers. The project aimed to test both the technical value of neighbourhood-embedded batteries and the commercial feasibility of offering household customers access to shared storage without the upfront cost of a home battery. There were three phases of the project: PowerBank (Meadow Springs), PowerBank2 (Falcon and Ellenbrook), and PowerBank3 (additional sites including Kalgoorlie, Vasse, Canning Vale and others). Technical set-up: each PowerBank installation consisted of a grid‑connected community battery operated by Western Power and integrated within the local distribution network. Customers with rooftop solar were able to virtually store excess solar generation produced between 7am and 3pm in the battery. Depending on the subscription selected, participants could use up to 6kWh or 8kWh of stored energy per day to offset consumption during periods when their own solar was not generating. The system provided no physical behind‑the‑meter flow of energy; instead, storage and discharge were modelled virtually through retail billing mechanisms. The batteries provided local network benefits by absorbing excess solar export during the day and smoothing power flows in areas with increasing rooftop PV penetration. Economics: across all three phases of the PowerBank pilot, 533 participants engaged in the virtual community battery scheme over a period of 3 years and 9 months. On average, each participant stored 6.53kWh of excess solar energy per day and consumed 6.3kWh from the community battery. The pilot demonstrated clear economic benefits for participating households, with an average annual bill saving of A$281.16 per participant. Allume Energy, Parkside, South Australia – type 1 shared-behind-the-meter[footnote 16] Context: in December 2019, Housing Choices Australia (HCA) completed the Mary Street project, which uses Allume Energy’s shared solar system to expand access to clean energy for residents in social and affordable housing. The initiative used the company’s SolShare platform to distribute solar power across multiple flats in a building, enabling households that cannot install individual rooftop systems to benefit from local renewable generation. Residents also benefit from shared battery storage, which increases local resilience by storing excess solar and supporting reliable operation during peak periods. Technical setup: the development comprises 54 flats supported by a shared onsite energy system that includes four solar PV arrays with a combined capacity of 73kWp (around 1.35kWp per flat) and four communal battery units providing 40kWh of storage (about 0.74kWh per flat). The setup dynamically allocates solar generation to residents based on demand and uses the shared batteries to enhance resilience and smooth peak loads across the building. Economics: the project has delivered environmental and financial gains by providing renewable energy to residents who have traditionally been unable to access it, despite physical roof constraints limiting the system size. Average grid electricity consumption reduced by 32% per flat and 195 tonnes of CO₂ emissions were avoided since commissioning. These reductions translate into meaningful household savings: cutting A$332 off annual electricity bills per apartment and directly addressing fuel poverty. Beyond Australia, there are examples in European countries such as the Netherlands and Germany, where community batteries are integrated into local energy systems, often alongside community solar schemes. However, deployment remains limited, usually focusing on smaller pilot projects rather than large-scale rollouts comparable to Australia’s nationwide programme. These examples demonstrate that community battery projects vary in technical design and ownership model. Their impact depends on a combination of factors, including market conditions, regulatory frameworks, and consumer engagement. These initiatives can provide valuable insights into how the benefits case for different consumer battery models can change under different conditions, an area we are keen to understand in more depth. Buurtbatterij pilot project, Netherlands – type 3 virtual power network[footnote 17] Context: in 2018, the Buurtbatterij (“neighbourhood battery”) pilot in Haarlemmermeer was initiated by Liander, the regional grid operator, in partnership with Tegenstroom, a local energy supplier that operates as part of an energy cooperative. Liander owned and operated the battery, while Tegenstroom played a key role in community outreach and coordination. 35 households took part. Participation in the project was free, though households were required to rent solar PV panels from Tegenstroom at a discounted rate, saving around €180 per year. The installation of panels was carried out in partnership with a social housing provider to ensure accessibility for a wide range of residents. The primary aim of the pilot was to stabilise the local grid, which faced increasing pressure from growing renewable generation. Technical set up: the community battery had a capacity of 50kW/130kWh and was installed in front of the residents’ meters, connected directly to the distribution network. Each participating household was equipped with ‘Lyv Dash’, an energy management software that enabled the monitoring of energy flows and optimisation of consumption. Economics: the pilot showed that community batteries can be beneficial for voltage management and offered revenue opportunities, such as providing balancing services through aggregators. There were consumer benefits as well: the community battery allowed residents to store surplus solar PV generation locally and draw on it when needed. The local community consumed 16,354kWh of self-generated solar energy through the battery, which is equivalent to the annual consumption of five households. However, the financial viability of the battery was low, which ultimately led to the removal of the battery in March 2021. Flex4Energy project, Germany – type 3 virtual private network[footnote 18] Context: the Flex4Energy project, led by ENTEGA AG between 2015 and 2018, explored how decentralised flexibility could support Germany’s energy transition while delivering tangible benefits to local communities. The pilot centred on the installation of a community battery “the Quartierspeicher” in Groß‑Umstadt, funded as part of a €4.21m programme. This shared residential battery project responded to residents’ reluctance to install individual home batteries due to space limitations and maintenance concerns. Technical set‑up: the community battery had a capacity of 250kW/115kWh and served 23 households. The households’ PV generation was used onsite first; any surplus was automatically stored free of charge in the shared battery or exported to the low‑voltage grid. ENTEGA equipped each home with a bidirectional meter and developed software coordinating household PV systems and the neighbourhood battery so they could jointly provide self‑consumption optimisation, local grid support and participation in wider energy markets. Economics: the community battery enabled households to use more of their own low‑cost solar power instead of purchasing electricity from the grid, increasing their self‑sufficiency from around 51% to up to 70%, directly reducing electricity bills. Households could view real‑time data on generation, export, import and self‑sufficiency. This shared storage model also allowed residents to avoid the significant upfront cost, space requirements, and ongoing maintenance associated with installing individual home batteries. Respondents are invited to share views on the following: Hazelmead community energy – type 2 microgrid new build[footnote 19] Context: in 2023, Bridport Cohousing (a community-led organisation), Barefoot Architects, Bournemouth Churches Housing Association, and Hazelmead Community Energy Limited, completed a new-build development of 54 homes installed on a microgrid in Bridport, Dorset. The project was motivated by a shortage of affordable, sustainable and community-oriented housing in the local area. The whole development cost just under £10m to construct and it is net zero in operation. Technical setup: a microgrid was set up as the estate was developed, integrating 210kWp of rooftop solar photovoltaic panels with a 1.6MWh Tesla battery, 10 EV chargers and a small amount of wind power. Economics[footnote 20]: by reducing electricity imports and generating export revenues, the microgrid reduced the electricity costs for the development as a whole by the equivalent of £1,300 annually per home (including costs like maintenance and insurance). However, given that this project was one of the first of its kind, the upfront investment and ongoing interest repayments exceeded these savings. As a result, whilst the project provided a 15% bill saving guarantee for residents compared to the price cap, it did so at a loss and remained financially unviable. To make the model feasible in future, a reduction in both technology and financing costs would be required. The cost of batteries has fallen significantly since 2023 and is continuing to fall. The cost of servicing the debt incurred to finance this type of project could decline over time if successful case studies are delivered and investor confidence in the approach is obtained. Brixton Urban Energy Club – type 3 virtual private network[footnote 21] Context: in 2021, a community battery was installed alongside existing solar PV on Elmore house, a low rise 1960s block owned by Lambeth Council and managed by Loughborough Estate Management Board. UK Power Networks used £195k of innovation funding from Ofgem’s Network Innovation Allowance to test the viability of a community battery to provide flexibility services and reduce consumer bills. Technical setup: a 10kW/20kWh battery was connected to the grid via a meter operated by EDF. This allowed EDF to virtually ‘net off’ energy provided by the battery to deliver bill savings to any EDF customers in the block of flats. They received bill credits for any solar they consumed, shared or sold to neighbours, as well as a share of the income from flexibility services. The platform optimised the use of the battery to increase residents’ savings. Economics: the trial required residents to be on an EDF tariff which resulted in just four out of the 63 households at Elmore House receiving benefits. In the final three months of the trial, in which PV savings, battery savings and flexibility savings were all provided, the four households received total savings equivalent to ~£180 annually. However, the trial ran over winter, so electricity usage and thus savings would likely be lower over a full year. A summary of evidence received will be published following analysis of responses. We appreciate the time and insight provided by all contributors. Your evidence will play an important role in helping us understand the benefits of community batteries, the conditions needed for their successful deployment, and any potential regulatory or policy changes that could support their rollout. As a final question as part of this call for evidence, we would welcome views on the following: * Lithium-ion batteries supplied for use in consumer products are in scope of the General Product Safety Regulations 2005. It is the responsibility of producers to ensure these batteries are safe. Businesses must also meet their obligations in the regulations to provide all relevant information, including safety warnings or instructions, with the product to enable safe use. * A Publicly Available Specification for “Protection against fire of battery energy storage systems for use in dwellings” (PAS 63100) was released in 2024 to provide fire-safety requirements for domestic batteries in the UK. Its purpose is to establish a national safety baseline by ensuring installers understand and mitigate fire safety related hazards by specifying safe siting, protective measures and controls, thereby reducing the risk of batteries becoming a source of ignition and limiting the impact of a battery fire should one occur. * Microgeneration Certification Scheme (MCS) standards (MIS 3012) govern installation practices for domestic batteries.[footnote 13] This standard sets out requirements for certified installers covering design, supply, and installation of electrical energy storage systems in homes. Its purpose is to ensure consistent, high‑quality, and competent installation, incorporating provisions for safe wiring, ventilation, fire protection, and commissioning checks to ensure systems are installed reliably and in line with recognised best practice.
E1·Energy Networks Association Innovation Portal·采集/快照 2026/8/10
Microresilience
Live ProjectReferenceNumber: NIA_NPG_018 Status: Live StartDate: 2017-09-01T00:00:00Z EndDate: 2020-09-01T00:00:00Z OwnerNetwork: Northern Powergrid TechnologyAreas: ["Environmental"] FundingMechanisms: ["Network Innovation Allowance"] StrategyThemes: [] Microresilience Status: Live Project Reference Number: NIA_NPG_018 START DATE: Sep 2017 END DATE: Sep 2020 Contact Lead Network Project summary Funding mechanism: Network Innovation Allowance Technology: Environmental Expenditure: £1,700,000 Third Party Collaborators: Smarter Grid Solutions LCP Delta Share project Save to my account Summary Learnings Documents Significant advances have been made in restoration of supplies by smart methods over recent years, in particular very short term restoration which is considered to be an increase in resilience. Conversely smart techniques have contributed less to increases in true resilience; situations when customers never experience an outage of any length in the first place. In the near future however improvements and cost reductions in battery technology, the prevalence of distributed generation particularly at lower voltages, and improvements in measurement and communications will offer smart opportunities to improve resilience. This would seem to be a potential low-cost route to improved true resilience but which mix of technology options, operational approaches would suit particular circumstances and locations is not known and the residual risk and actual deliverable benefit is not understood. Objectives The project will assess the technical viability and comparative economics (including non-financial benefits) of smart technology enabled resilience under the following circumstances: Critical customers on vulnerable connection Remote customers on vulnerable connection Opportune micro-grid application (using already present DG) Simple storage option The project intends to provide guidance for the appropriateness of the various solutions tested and their technical benefits and disadvantages. The level of resilience improvement will be assessed alongside the level desired by the customers. Critical customers on a vulnerable connection may have different requirements to a microgrid implementation with a significant degree of embedded generation. View Project as PDF Select all Title Date modified Document type NIA_NPG_018 Annual Progress Report (5) 2026-06-15 1_44 (35.2 KB) 2026-06-15 2026-06-15 pdf NIA_NPG_018 Annual Progress Report (4) 2025-07-21 3_04 (35.5 KB) 2025-07-21 2025-07-21 pdf NIA_NPG_018 Annual Progress Report (3) 2024-07-23 7_51 (35.5 KB) 2024-07-23 2024-07-23 pdf NIA Project Registration and PEA Document_Microresilience NPG_NIA_018.pdf (209.4 KB) 2024-02-22 2024-02-22 pdf Customer Impact Dashboard.pdf (128.3 KB) 2024-02-22 2024-02-22 pdf NIA_NPG_018 Annual Progress Report (2) 2023-07-31 9_33 (35.6 KB) 2023-07-31 2023-07-31 pdf NIA_NPG_018 Annual Progress Report (1) 2022-07-30 10_22 (34.1 KB) 2022-07-30 2022-07-30 pdf NIA_NPG_018 Annual Progress Report 2021-07-27 2_55 (62.0 KB) 2021-07-27 2021-07-27 pdf NIA Project Registration and PEA Document (83.5 KB) 2021-03-25 2021-03-25 pdf NIA_NPG_018 (03-08-2017 11-06-50) (39.4 KB) pdf NIA_NPG_018 (14-02-2018 08-32-25) (46.9 KB) pdf NIA_NPG_018 (21-02-2018 12-20-26) (46.9 KB) pdf NIA_NPG_018 (30-07-2018 13-33-11) (26.3 KB) pdf NIA_NPG_018 (30-07-2019 14-39-21) (26.8 KB) pdf NIA_NPG_018 (31-07-2020 12-36-10) (30.4 KB) pdf project-difference (08-04-2021 15-23-27) (8.4 KB) xlsx Download Learnings Outcomes Outcomes and findings will be covered comprehensively in the closedown reports scheduled for completion and release in Q3 2026. Lessons Learnt During the hiatus of the recent pandemic additional effort was channelled into the interoperability of the microgrid control interface. Legacy storage systems were difficult to support regarding software and firmware updates. Research during this phase found a distinct lack of sub 1MW storage systems available in the UK, with several vendors tending to prefer the larger 5MW systems. Existing energy markets are well established regarding this level of capacity with existing ROI’s being met through the grid frequency support mechanism. As DNO’s begin the transition towards DSO’s there will be additional focus on smaller domestic, SME/I and C energy storage levels. These DER’s will form the basis of a new emerging market focused on local resilience and featuring peer to peer trading.
E1·UK Department for Energy Security and Net Zero·采集/快照 2026/8/12
UK community and grid-scale battery safety evidence
4. Ensuring safety 4.1 Introduction to battery safety risks 4.2 Grid-scale batteries 4.3 Domestic batteries 4.4 Community batteries 5.1 Australia 5.2 Europe 5.3 UK Lithium-ion batteries have become part of everyday life, from phones and laptops through e-bikes and electric cars to the standalone home and community storage units on which this document focuses. For most people, use of lithium-ion batteries is without incident, but they do carry a risk of fire, particularly if improperly built or installed. That risk does not mean that batteries cannot be used safely – after all, most UK homes contain gas boilers, which similarly pose significant risks if poorly installed or maintained – but does mean that, as for gas boilers, it is important that safety is taken seriously, particularly in design and installation. This section provides an overview of the inherent safety risks associated with battery technologies and the existing regulatory and standards frameworks that apply across domestic and grid‑scale storage. We are seeking views on whether these frameworks remain appropriate and proportionate for community batteries as deployment increases, and whether any gaps in standards, responsibilities, or risk management need to be addressed. Like many modern appliances, from boilers to mobile phones, the components used in batteries have the potential to cause harm, and so it is important that in their manufacture, installation and use, consideration is given as to how most effectively to mitigate that harm. Domestic and grid-scale batteries mainly use lithium‑ion chemistries, with some sodium‑ion systems emerging. Lithium‑ion and sodium‑ion cells hold large amounts of chemical energy in a compact structure. Cells are packaged into modules and packs, controlled by a Battery Management System (BMS) to keep voltage, temperature, and current within safe limits. This energy is normally stable as long as the separator keeps electrodes apart and the BMS regulates charging and temperature. Fire incidents involving lithium‑ion batteries used in mobile applications - such as e‑bikes and e‑scooters, particularly when unlawfully retrofitted - have been documented. However, there is no evidence to suggest that fire incidents involving professionally installed domestic battery storage systems are a common occurrence. These systems are substantial, stationary units that are subject to established regulatory requirements and technical standards that apply to battery manufacture, installation, and operation. Nevertheless, risks may arise where systems are not correctly installed. Community batteries are expected to meet the same baseline safety expectations as other energy storage assets. The overview below therefore provides context for considering whether existing frameworks remain appropriate and proportionate as the sector grows. This document focuses on community batteries, but it is contextually useful to outline the safety regime that exists for larger batteries connected directly to transmission and distribution networks. While fires have occurred at battery sites in Great Britain, they are rare. Fires at grid-scale battery sites are less frequent than those at non-domestic buildings from all sources. The latest available 5-year annual average fire incidence rate for grid-scale batteries is 0.7% (2020/21 to 2024/25),[footnote 11] lower than non-domestic building fires in England at 0.8% (2020/21 to 2024/25).[footnote 12] This risk is mitigated by a robust regulatory framework overseen by the Health and Safety Executive (HSE). This framework requires responsible parties to take measures to ensure health and safety throughout all stages of a battery system’s deployment. It is important that those involved in the deployment of BESS sites are aware of their legal duties. HSE supports this with guidance on its website. Where health and safety standards are concerned, best practice is reflected in common international standards such as National Fire Protection Association’s NFPA 855 Standard for the Installation of Stationary Energy Storage Systems , as well as Underwriters Laboratories’ UL9540A Test Method for Battery Energy Storage Systems (BESS) which is the critical test method for thermal runaway propagation. American standards, such as those developed by NFPA and UL, are normally applied to BESS projects in the UK as there are no currently developed UK or EU equivalent standards. These American standards are recognised globally and the UK insurance industry typically mandates them as a requirement of its insurance agreements. The government works closely with the Electricity Storage Health and Safety Governance Group, whose members include the Health and Safety Executive (HSE), National Fire Chiefs Council, and the Environment Agency. The Governance Group is responsible for ensuring that an appropriate, robust and future-proofed health and safety framework is sustained. As part of this work, the Group has developed and published health and safety guidance for grid-scale batteries. The guidance aims to improve the navigability of existing standards and provide a clearer understanding of relevant H&S standards. The government, through the industry-led Electricity Storage Health and Safety Governance Group, will continue to monitor the sector closely. In August 2025, DEFRA launched a consultation on including grid-scale batteries within the Environmental Permitting Regulations, to provide further safeguards and assurance. DEFRA is currently analysing feedback to this consultation and will publish a government response in due course. For domestic battery storage systems, as with any electrical appliance, there is an inherent risk of fire which cannot be completely eliminated. As for other household appliances, government sets safety standards, but individuals and property owners are best placed to make informed decisions about installation and use, supported by certified installers, product information and the specific characteristics of their property. A range of UK regulations and standards significantly reduce risk and ensure safe installation and operation: In addition to the regulatory and standards framework set out above, the government previously commissioned a detailed review of the safety risks associated with domestic lithium-ion battery energy storage systems in 2020. This review, carried out for the Office for Product Safety and Standards (OPSS) and the then Department for Business, Energy & Industrial Strategy (BEIS), examined the operation of domestic battery systems, known incident data, potential failure modes (including thermal runaway), and the effectiveness of existing and emerging mitigation measures. The review also provides an overview of relevant safety standards and codes of practice. Community batteries differ significantly from domestic batteries, in size, location and ownership. They typically have higher total power, energy capacity and voltage, serve multiple households or businesses, and may be installed in shared or public spaces where access and emergency planning needs careful thought. They can also involve varied ownership and maintenance models, which means responsibilities for ongoing safety checks must be clear. While these characteristics do not in themselves indicate a higher level of risk, they do create a different risk profile compared to domestic batteries and raise important questions about whether standards designed for small-scale, single-property installations are sufficient for community-scale projects. For example, PAS 63100 excludes dwellings over 200 m², and MIS 3012 only applies to systems below 50kW. We have identified community batteries in the UK that fall outside the scope of both standards. We want to understand what gaps exist, whether these gaps pose any risks, and what additional measures might be needed. Current and prospective community battery users, as well as relevant local authorities (including fire services), are invited to share views on the following: As noted, community battery projects are already operating in the UK, and we are keen to highlight some examples. Similar initiatives are emerging internationally, particularly in Australia, offering valuable lessons for UK. We are keen to share these insights while also learning from projects developed here at home. One prominent example is Australia’s ‘Community Batteries for Household Solar’ programme, supported by A$200m in federal funding. This initiative aims to deploy around 400 community battery systems nationwide, enabling communities to store excess rooftop solar energy and access affordable power. The programme has attracted significant attention. In June 2024, the Australian Renewable Energy Agency’s (ARENA) awarded A$124.7m in Round 1 to fund 318 batteries ranging from 50kW to 5MW. The application round for Round 2, offering A$46.3m, closed in September 2025. The Department of Industry, Science and Resources is separately administering A$29m of the available grant funding.[footnote 14] This approach has been particularly effective in Australia because high levels of domestic solar generation means that distribution networks are often constrained by excess daytime exports, as large volumes of surplus solar generation flow back into the grid simultaneously. This can lead to grid congestion and force distribution network operators to impose export limits. Community batteries are therefore strategically installed within local distribution networks to store surplus solar energy generated during the day before it reaches the wider grid and release it during peak demand periods. This model benefits both solar and non-solar households: participants can rent storage capacity, earn credits for stored energy, and enjoy lower bills. However, like all retrofit virtual private networks, consumers must switch to a specific supplier to benefit. While uptake has been strong in engaged suburban areas, there have been some challenges in onboarding more vulnerable households. We are keen to explore whether this model, or similar approaches, could be adapted for the UK to deliver benefits such as bill savings for low-income households. PowerBank Community Battery pilot, Western Australia – type 3 virtual private network[footnote 15] Context: PowerBank was a joint pilot by Synergy and Western Power exploring the potential of community‑scale batteries to support Western Australia’s South West Interconnected System (SWIS). Delivered across 12 metropolitan and regional locations, it was the first pilot in Australia to integrate a utility‑scale battery into an existing major metropolitan electricity network for the purpose of providing virtual storage to individual customers. The project aimed to test both the technical value of neighbourhood-embedded batteries and the commercial feasibility of offering household customers access to shared storage without the upfront cost of a home battery. There were three phases of the project: PowerBank (Meadow Springs), PowerBank2 (Falcon and Ellenbrook), and PowerBank3 (additional sites including Kalgoorlie, Vasse, Canning Vale and others). Technical set-up: each PowerBank installation consisted of a grid‑connected community battery operated by Western Power and integrated within the local distribution network. Customers with rooftop solar were able to virtually store excess solar generation produced between 7am and 3pm in the battery. Depending on the subscription selected, participants could use up to 6kWh or 8kWh of stored energy per day to offset consumption during periods when their own solar was not generating. The system provided no physical behind‑the‑meter flow of energy; instead, storage and discharge were modelled virtually through retail billing mechanisms. The batteries provided local network benefits by absorbing excess solar export during the day and smoothing power flows in areas with increasing rooftop PV penetration. Economics: across all three phases of the PowerBank pilot, 533 participants engaged in the virtual community battery scheme over a period of 3 years and 9 months. On average, each participant stored 6.53kWh of excess solar energy per day and consumed 6.3kWh from the community battery. The pilot demonstrated clear economic benefits for participating households, with an average annual bill saving of A$281.16 per participant. Allume Energy, Parkside, South Australia – type 1 shared-behind-the-meter[footnote 16] Context: in December 2019, Housing Choices Australia (HCA) completed the Mary Street project, which uses Allume Energy’s shared solar system to expand access to clean energy for residents in social and affordable housing. The initiative used the company’s SolShare platform to distribute solar power across multiple flats in a building, enabling households that cannot install individual rooftop systems to benefit from local renewable generation. Residents also benefit from shared battery storage, which increases local resilience by storing excess solar and supporting reliable operation during peak periods. Technical setup: the development comprises 54 flats supported by a shared onsite energy system that includes four solar PV arrays with a combined capacity of 73kWp (around 1.35kWp per flat) and four communal battery units providing 40kWh of storage (about 0.74kWh per flat). The setup dynamically allocates solar generation to residents based on demand and uses the shared batteries to enhance resilience and smooth peak loads across the building. Economics: the project has delivered environmental and financial gains by providing renewable energy to residents who have traditionally been unable to access it, despite physical roof constraints limiting the system size. Average grid electricity consumption reduced by 32% per flat and 195 tonnes of CO₂ emissions were avoided since commissioning. These reductions translate into meaningful household savings: cutting A$332 off annual electricity bills per apartment and directly addressing fuel poverty. Beyond Australia, there are examples in European countries such as the Netherlands and Germany, where community batteries are integrated into local energy systems, often alongside community solar schemes. However, deployment remains limited, usually focusing on smaller pilot projects rather than large-scale rollouts comparable to Australia’s nationwide programme. These examples demonstrate that community battery projects vary in technical design and ownership model. Their impact depends on a combination of factors, including market conditions, regulatory frameworks, and consumer engagement. These initiatives can provide valuable insights into how the benefits case for different consumer battery models can change under different conditions, an area we are keen to understand in more depth. Buurtbatterij pilot project, Netherlands – type 3 virtual power network[footnote 17] Context: in 2018, the Buurtbatterij (“neighbourhood battery”) pilot in Haarlemmermeer was initiated by Liander, the regional grid operator, in partnership with Tegenstroom, a local energy supplier that operates as part of an energy cooperative. Liander owned and operated the battery, while Tegenstroom played a key role in community outreach and coordination. 35 households took part. Participation in the project was free, though households were required to rent solar PV panels from Tegenstroom at a discounted rate, saving around €180 per year. The installation of panels was carried out in partnership with a social housing provider to ensure accessibility for a wide range of residents. The primary aim of the pilot was to stabilise the local grid, which faced increasing pressure from growing renewable generation. Technical set up: the community battery had a capacity of 50kW/130kWh and was installed in front of the residents’ meters, connected directly to the distribution network. Each participating household was equipped with ‘Lyv Dash’, an energy management software that enabled the monitoring of energy flows and optimisation of consumption. Economics: the pilot showed that community batteries can be beneficial for voltage management and offered revenue opportunities, such as providing balancing services through aggregators. There were consumer benefits as well: the community battery allowed residents to store surplus solar PV generation locally and draw on it when needed. The local community consumed 16,354kWh of self-generated solar energy through the battery, which is equivalent to the annual consumption of five households. However, the financial viability of the battery was low, which ultimately led to the removal of the battery in March 2021. Flex4Energy project, Germany – type 3 virtual private network[footnote 18] Context: the Flex4Energy project, led by ENTEGA AG between 2015 and 2018, explored how decentralised flexibility could support Germany’s energy transition while delivering tangible benefits to local communities. The pilot centred on the installation of a community battery “the Quartierspeicher” in Groß‑Umstadt, funded as part of a €4.21m programme. This shared residential battery project responded to residents’ reluctance to install individual home batteries due to space limitations and maintenance concerns. Technical set‑up: the community battery had a capacity of 250kW/115kWh and served 23 households. The households’ PV generation was used onsite first; any surplus was automatically stored free of charge in the shared battery or exported to the low‑voltage grid. ENTEGA equipped each home with a bidirectional meter and developed software coordinating household PV systems and the neighbourhood battery so they could jointly provide self‑consumption optimisation, local grid support and participation in wider energy markets. Economics: the community battery enabled households to use more of their own low‑cost solar power instead of purchasing electricity from the grid, increasing their self‑sufficiency from around 51% to up to 70%, directly reducing electricity bills. Households could view real‑time data on generation, export, import and self‑sufficiency. This shared storage model also allowed residents to avoid the significant upfront cost, space requirements, and ongoing maintenance associated with installing individual home batteries. Respondents are invited to share views on the following: Hazelmead community energy – type 2 microgrid new build[footnote 19] Context: in 2023, Bridport Cohousing (a community-led organisation), Barefoot Architects, Bournemouth Churches Housing Association, and Hazelmead Community Energy Limited, completed a new-build development of 54 homes installed on a microgrid in Bridport, Dorset. The project was motivated by a shortage of affordable, sustainable and community-oriented housing in the local area. The whole development cost just under £10m to construct and it is net zero in operation. Technical setup: a microgrid was set up as the estate was developed, integrating 210kWp of rooftop solar photovoltaic panels with a 1.6MWh Tesla battery, 10 EV chargers and a small amount of wind power. Economics[footnote 20]: by reducing electricity imports and generating export revenues, the microgrid reduced the electricity costs for the development as a whole by the equivalent of £1,300 annually per home (including costs like maintenance and insurance). However, given that this project was one of the first of its kind, the upfront investment and ongoing interest repayments exceeded these savings. As a result, whilst the project provided a 15% bill saving guarantee for residents compared to the price cap, it did so at a loss and remained financially unviable. To make the model feasible in future, a reduction in both technology and financing costs would be required. The cost of batteries has fallen significantly since 2023 and is continuing to fall. The cost of servicing the debt incurred to finance this type of project could decline over time if successful case studies are delivered and investor confidence in the approach is obtained. Brixton Urban Energy Club – type 3 virtual private network[footnote 21] Context: in 2021, a community battery was installed alongside existing solar PV on Elmore house, a low rise 1960s block owned by Lambeth Council and managed by Loughborough Estate Management Board. UK Power Networks used £195k of innovation funding from Ofgem’s Network Innovation Allowance to test the viability of a community battery to provide flexibility services and reduce consumer bills. Technical setup: a 10kW/20kWh battery was connected to the grid via a meter operated by EDF. This allowed EDF to virtually ‘net off’ energy provided by the battery to deliver bill savings to any EDF customers in the block of flats. They received bill credits for any solar they consumed, shared or sold to neighbours, as well as a share of the income from flexibility services. The platform optimised the use of the battery to increase residents’ savings. Economics: the trial required residents to be on an EDF tariff which resulted in just four out of the 63 households at Elmore House receiving benefits. In the final three months of the trial, in which PV savings, battery savings and flexibility savings were all provided, the four households received total savings equivalent to ~£180 annually. However, the trial ran over winter, so electricity usage and thus savings would likely be lower over a full year. A summary of evidence received will be published following analysis of responses. We appreciate the time and insight provided by all contributors. Your evidence will play an important role in helping us understand the benefits of community batteries, the conditions needed for their successful deployment, and any potential regulatory or policy changes that could support their rollout. As a final question as part of this call for evidence, we would welcome views on the following: * Lithium-ion batteries supplied for use in consumer products are in scope of the General Product Safety Regulations 2005. It is the responsibility of producers to ensure these batteries are safe. Businesses must also meet their obligations in the regulations to provide all relevant information, including safety warnings or instructions, with the product to enable safe use. * A Publicly Available Specification for “Protection against fire of battery energy storage systems for use in dwellings” (PAS 63100) was released in 2024 to provide fire-safety requirements for domestic batteries in the UK. Its purpose is to establish a national safety baseline by ensuring installers understand and mitigate fire safety related hazards by specifying safe siting, protective measures and controls, thereby reducing the risk of batteries becoming a source of ignition and limiting the impact of a battery fire should one occur. * Microgeneration Certification Scheme (MCS) standards (MIS 3012) govern installation practices for domestic batteries.[footnote 13] This standard sets out requirements for certified installers covering design, supply, and installation of electrical energy storage systems in homes. Its purpose is to ensure consistent, high‑quality, and competent installation, incorporating provisions for safe wiring, ventilation, fire protection, and commissioning checks to ensure systems are installed reliably and in line with recognised best practice.
E1·Energy Networks Association Innovation Portal·采集/快照 2026/9/7
Project VOLT (Alpha)
Live ProjectReferenceNumber: NPG_SIF_025 Status: Live StartDate: 2026-02-01T00:00:00Z EndDate: 2026-08-01T00:00:00Z OwnerNetwork: Northern Powergrid TechnologyAreas: ["Hydrogen","Low Carbon Generation","Demand Side Management","Distributed Generation","Energy Storage","Energy Storage and Demand Response","Gas Distribution Networks","Green Gas"] FundingMechanisms: ["SIF Alpha - Round 4"] StrategyThemes: ["Whole energy systems"] Project VOLT (Alpha) Status: Live Project Reference Number: NPG_SIF_025 STRATEGY THEME: Whole energy systems START DATE: Feb 2026 END DATE: Aug 2026 Contact Lead Network Project summary Lead Funding Licensee: NPg - Northern Powergrid (Northeast) Limited Funding mechanism: SIF Alpha - Round 4 Technology: Hydrogen Low Carbon Generation Demand Side Management Distributed Generation Energy Storage Energy Storage and Demand Response Gas Distribution Networks Green Gas Expenditure: £551,251 Preceding Projects: NPG/PV/FND/Rd4_Discovery Third Party Collaborators: Newcastle University EDF Energy LCP Delta Pulsant Share project Save to my account Summary Documents Project Summary Project VOLT Alpha builds on earlier work to develop and validate how multi-vector microgrids can help industrial and commercial sites decarbonise, improve resilience, and provide flexibility. With support from Newcastle Airport, Port of Tyne, Nissan, Pulsant, and Severfield, it targets high-emission zones like ports, airports, and data centres. The Alpha phase will deliver scalable microgrid blueprints and operational processes aligned with national and regional strategies. Backed by NECA, NESO, NGET, and new partners EDF and Wales&West Utilities, VOLT supports the Clean Flexibility Roadmap by unlocking I&C flexibility and accelerating GB's transition to a low-carbon, resilient energy system. Innovation Justification Innovation challenge theme Project VOLT offers a novel, ambitious approach to industrial decarbonisation and energy system resilience. It unlocks flexibility from I&C customers and delivers replicable regional energy system models, directly addressing SIF Round 4 Challenge 1 -- Theme 2. Building on Discovery , Alpha shifts from feasibility to deliverability, developing multi-vector microgrid models tailored to different customer types. These models support regional balancing, accelerate low-carbon deployment, and enhance resilience for both networks and customers. Unlike traditional single-vector microgrids, VOLT pioneers a multi-vector framework integrating electricity, gas, hydrogen, and storage. This enables co-optimisation across carbon, cost, and resilience, delivering dynamic load balancing, peak shaving, and system flexibility. The Alpha Phase will produce detailed blueprints, quantify system-level benefits, and align operations with planning frameworks (RESP, SSEP). VOLT is well-suited to SIF due to its whole-system scope and cross-network coordination. It tackles regulatory, commercial, and operational barriers beyond BaU mechanisms. The project is grounded in real-world constraints and supports the evolution of flexible, low-carbon energy markets. Novelty and state-of-the-art advancement VOLT represents a step-change in industrial energy design, integrating multiple vectors and co-optimising across cost, carbon, and resilience. This surpasses conventional models focused on single objectives. Advanced system modelling will simulate microgrid operations across diverse industrial sites, capturing interactions between demand, constraints, and planning. The project will assess how microgrids support regional balancing, black start capability, and low-carbon connections, while aligning with RESP, SSEP. By combining technical feasibility with stakeholder-specific design and whole-system coordination, VOLT delivers a scalable, replicable blueprint for industrial decarbonisation. Building on Discovery The Discovery Phase validated the feasibility of multi-vector microgrids and their potential to meet carbon, cost, and resilience goals when coordinated with upstream networks. It also identified key regulatory, commercial, and system-level challenges, shaping Alpha's focus on deliverability. To address these, the consortium now includes NGET, Wales&West Utilities, and NECA, ensuring full consideration of transmission, regional planning, and system coordination. The customer base has expanded to include Pulsant (data centre) and Severfield (steel manufacturer), enabling testing across varied operational profiles. These additions reflect growing demand for resilient, low-carbon solutions in energy-intensive sectors. Letters of support are attached to this question, (NGET's submitted separately). Lessons from Discovery and other SIF projects like ReFLEX and Distributed ReStart confirm the need for tailored, scalable models aligned with stakeholder priorities. VOLT Alpha is designed to meet this need. Technical and commercial readiness At Discovery's end, VOLT had reached: TRL3--4: Concept validated; initial modelling complete.IRL2--3: Early integration with network data and planning.CRL2--3: Strong stakeholder and customer interest.By Alpha's end, VOLT aims for: TRL5: Operational models tested across industrial sites.IRL4: Integration with RESP, SSEP, and planning frameworks.CRL4--5: Defined route-to-market with tailored value propositionsWhy SIF? VOLT's complexity, systemic scope, and cross-sector coordination place it beyond the remit of BaU funding. It addresses uncertain data, regulatory gaps, and stakeholder engagement needs not typically resourced. The project prioritises consumer protection, resilience, and strategic planning---aligning with SIF's public benefit mission. Stakeholder engagement and co-design Alpha has been shaped through collaboration with EDF, NESO, NGET, Wales&West Utilities, and NECA. Their input ensures the project addresses challenges across the energy system. Engagement with new customer sites ensures replicability across diverse users. This inclusive approach fosters transparency, challenge, and collaboration, reinforcing VOLT's system-wide impact. Counterfactuals Without multi-vector microgrids, I&C customers would face up to 62% higher energy costs and 47% higher emissions, as shown in Discovery baselines for customers. VOLT Alpha offers a scalable, practical solution to meet decarbonisation needs, enhance resilience, and unlock I&C flexibility---supporting government objectives. Only SIF can enable a whole-system, multi-party innovation with public benefit at its core. Impacts and Benefits Impacts and benefits description Project VOLT offers substantial benefits for customers, networks, and wider stakeholders. Multi-vector microgrids reduce peak network loads, deferring reinforcement and enabling faster renewable connections. Coordinated regional microgrids provide flexibility and resilience services, while helping I&C customers cut energy costs, improve security, and meet decarbonisation goals. The project also strengthens the business case for commercialising new technologies, supporting regional development in line with the Government's Clean Energy Superpower Mission. Pre-innovation baseline and challenges I&C sites currently depend on centralised energy supply, resulting in high costs, emissions, and limited flexibility. Most demand is met via direct electricity and gas imports, with peak usage driving grid congestion and reinforcement needs. Fossil fuel reliance increases emissions, and industrial flexibility and multi-vector integration remain largely untapped. Forecast net benefits If adopted as BaU, VOLT could deliver: £19-40 million in avoided network reinforcement over 25 years by reducing peak demand and optimising cross-vector flows.15-62% annual energy bill savings per I&C customer via on-site generation, renewable export optimisation, demand-side management, and reduced peak-time grid reliance.Up to 1,800 tonnes of direct CO₂ savings annually from reduced fossil fuel use.10,000-40,000 tonnes of indirect CO₂ savings annually by reducing reliance on carbon-intensive peaking plants.Up to £1 million in lifetime flexibility revenue for industrial users.Resilience benefits valued at up to £1 million/year (or £3 million/year for mission-critical sites), based on Value of Lost Load estimates.Alpha benefits While Alpha won't deliver direct consumer benefits, it will generate outputs valuable to I&C customers, networks, NESO, and planners: Design blueprints and operational processes for different customer types, with case studies applicable across GB, enabling decarbonisation without major network upgrades.Policy and regulatory recommendations and a deliverability roadmap to support innovation trials or BaU development.CBA toolkits and guidance to support future trials and deployments.Flexibility potential analysis and alignment with NESO system operation strategies, including recommendations for new products supporting the Clean Flexibility Roadmap.System coordination insights at regional and national levels, feeding into RESP, SSEP, NECA's Spatial Development Strategy, and the Energy Review.A Beta phase roadmap, detailing how Alpha insights will transition into real-world demonstrations, identifying optimal sites, readiness requirements, and integration pathways with decarbonisation and network plans.'Other' benefits: social and equity impacts VOLT also delivers broader societal and environmental benefits: Attracting investment by offering cost-effective, resilient energy to high-demand users.Creating green jobs and high-value employment.Strengthening local supply chains.Driving innovation aligned with GB's energy transition.Supporting decarbonisation of high-energy users, improving air quality.The accompanying CBA and Business Case use Discovery Phase outputs and current BaU assumptions, including existing energy demand levels. Further analysis during Alpha will refine these based on evolving demand and generation trends through 2050. This will inform key cost--benefit metrics such as peak demand reduction, flexibility market participation, and energy bill savings, using WP2, WP5, and WP7. Beta phase vision In Beta, VOLT will move from design to demonstration at one or more I&C sites, combining real-world deployment with simulation to validate Alpha findings. The Beta phase will: Deploy a pilot multi-vector microgrid integrating renewables, battery storage, hydrogen CHP, and smart controls.Demonstrate flexibility provision to NESO and DSO markets.Quantify system and customer benefits: emissions reduction, peak shaving, deferred upgrades, improved continuity, and resilience.Test commercial models and market participation mechanisms.Validate digital and control tools for on-site and system-level coordination.Establish a roadmap for scaling from innovation to BaU deployment across GB. View Project as PDF Select all Title Date modified Document type WP7 - Wider system coordination and benefits assessment (M7.1).pptx (8.6 MB) 07/09/2026 07/09/2026 pptx WP4 - Market, policy, regulation, fuels and technology assessment (M4.5).pptx (14.6 MB) 07/09/2026 07/09/2026 pptx WP3 - Microgrid designs and operational process maps and roles (M3.2 & M3.3).pptx (10.0 MB) 07/09/2026 07/09/2026 pptx WP3 - Integration plan and roadmap for innovation trial (M3.4).pptx (8.8 MB) 07/09/2026 07/09/2026 pptx WP3 - Customer classification and prioritisation framework (M3.1).xlsx (49.9 KB) 07/09/2026 07/09/2026 xlsx WP2 - Stakeholder strategy (M2.1).pptx (12.7 MB) 07/09/2026 07/09/2026 pptx WP1 - Project kick-off (M1.1).pptx (18.8 MB) 07/09/2026 07/09/2026 pptx WP1 - Midpoint report (M1.2).pptx (9.4 MB) 07/09/2026 07/09/2026 pptx WP1 - End of Phase reporting (M1.3).pptx (8.9 MB) 07/09/2026 07/09/2026 pptx SIF Alpha Round 4 Project Registration 2026-03-30 10_50 (78.6 KB) 30/03/2026 30/03/2026 pdf Download