This project will support the strategic improvement and evolvement of the planning and connections process to meet net zero in a timely and cost-effective manner. The current connection process has been identified as being over-subscribed, representing a bottleneck. To achieve the Net Zero targets of the country, it is considered necessary to support the development, implementation and connection of low carbon technologies onto the electricity network. This project will be a feasibility study, and would look to investigate, develop and trial new technical and procedural issues associated with connection applications for new developments. It will help maximise potential additional distributed generation on the grid by implementing a "smart island" microgrid for a specified network community. Export and import capacity requirements would be reduced, compared to a standard firm connection.
Benefits
Merits:
Simplifying community connections and reducing the costs and lengthy application windows associated with network reinforcement. Improve queue management and supporting the roll-out of low carbon solutions.
The project will enable the prompt introduction of numerous low-carbon technologies at scale within a self-managed network, without the requirement for major grid reinforcement.
The connections queue can be efficiently managed to ensure the above benefit can be realised
Faster and cheaper network transformation can occur
Learnings throughout are captured and used to promote a BaU design and connection application process
Benefits - This project will support the business strategy to:
- Develop a Net-Zero network and support the transition to DSO by enhancing our connections service
- Transition from service provider to partner by supporting communities achieve Net Zero transition
- Prepare the business for a sustainable and digital future by supporting the development of Microgrids
Learnings
Outcomes
Work Package 1: WP1 aimed to review SP Energy Networks' (SPEN) generation connection policy and provide recommendations for future updates to streamline the connection process. The approach involved benchmarking SPEN's policy against those of other Distribution Network Operators (DNOs) and the EREC G98 and G99 standards, which are essential for integrating distributed generation projects. The output was a gap analysis with proposed recommendations to ensure future policy updates comply with the latest standards and anticipated market changes, making revisions clear and unambiguous for prospective customers.
Work Package 2: WP2 involved an international review of community microgrid developments and best practices, focusing on key regulatory developments, technical considerations, and relevant case studies. Despite limited progress in the UK, similar innovation projects were reviewed to extract key learnings. The research primarily concentrated on developments in Spain, the Nordic region, other EU countries, and North America, providing a comprehensive overview of the current landscape and insights for future advancements in community microgrids. Community microgrids require significant upfront costs and require specialised expertise to manage the energy system. The reliance on diesel backup generators can conflict with sustainability goals. Community microgrids also face unique regulatory challenges and/or policy gaps.
Work Package 3: WP3 focused on conducting a high-level Cost Benefit Analysis (CBA) for implementing community microgrids on SP Energy Networks' distribution system. The analysis evaluated the financial costs of deploying this innovative solution and highlighted potential benefits, such as avoided network reinforcement costs and reduced carbon emissions. The CBA followed the RIIO-2 Cost Benefit Analysis Guidance from Ofgem, ensuring alignment with best practices. The outputs present a business case for integrating community microgrids into SP Energy Networks' distribution system, serving as a reference for future work.
The main financial benefit of implementing microgrids will be avoiding network reinforcement costs in sites,
Work Package 3: WP3 focused on conducting a high-level Cost Benefit Analysis (CBA) for implementing community microgrids in the distribution network of SP Energy Networks. Distribution Energy Scenario data was collected for all the distribution substations in network and the available headroom was calculated for each substation from 2025 to 2050. A microgrid is to be installed behind the meter for substations with negative headroom. This microgrid will help avoid network reinforcement costs. With network reinforcement costs of £1M/MVA, a full-scale rollout is projected to deliver discounted cumulative net financial benefits of £242.34 million and net environmental benefits of £28.88 million, resulting in a total net present value (NPV) of £271.22 million by 2050. The study also evaluated alternative deployment levels, including 20%, 40%, 60%, and 80% rollouts. These partial rollouts yield proportionally lower but still significant benefits. For example, a 20% rollout results in a total NPV of £54.24 million, while an 80% rollout achieves an NPV of £216.97 million.
Work Package 4: WP4 focused on assessing the feasibility of integrating community microgrids into the distribution network by evaluating technical, operational, financial, and regulatory aspects. It tested microgrid solutions for improving connection lead times and enhancing network reliability and resilience, especially during peak demand and outages. The analysis also considered the potential of microgrids to support the UK's decarbonisation and net zero goals. Additionally, WP4 involved developing and refining rules and mechanisms to optimize grid operations, investigating community engagement models, assessing economic impacts, identifying barriers to large-scale deployment, and defining strategies for commercialisation or business-as-usual implementation.
The potential for new learning includes improving coordination, modelling, and planning capabilities across networks to support holistic and timely system development. This project aims to accelerate connection times for renewables and/or demand sites to meet the 2030 target. It will also support the prioritisation of flexible assets in connection queues, increasing network headroom and reducing the time for viable assets to secure connections. Additionally, it seeks to improve the availability of information to consumers, enabling more cost-effective and diverse decarbonisation choices.
Lessons Learnt
This research project provided several important lessons that can help guide future work in the energy sector, particularly in the areas of low-carbon technologies and community energy. One of the key findings was the importance of addressing connection and queue management challenges early. These issues often slow down progress, so future projects should look at managing the connection queue more actively and aim to connect projects that are ready to go first. This would help make better use of available capacity and avoid unnecessary delays.
Another important lesson was the need to keep generation connection policies up to date. As technology, regulations, and customer needs change, policies must be reviewed and adjusted to stay relevant. Standardising the application process and making it easier to understand can help reduce confusion and improve the experience for both customers and network operators. It is also important to clearly communicate any changes so that everyone involved knows what to expect.
The project also highlighted a lack of UK-specific guidance on microgrids. To overcome this, the team looked internationally reviewing global standards such as IEEE and IEC and speaking with experts who have experience in community microgrids. This approach proved valuable and showed that even when local information is limited, there are still ways to gather useful insights by learning from others.
Energy communities were identified as a promising way to support the energy transition. They can help people take part in local energy projects, support rural and local economies, and reduce energy poverty by allowing energy sharing with nearby households. These communities also add flexibility to the grid and can act as testing grounds for new ideas. Future projects should look at how to support and grow these kinds of community-led efforts.
Finally, the research showed that it is possible to plan for the large-scale use of low-carbon technologies without needing major upgrades to the electricity grid. By designing smarter, more flexible systems, future projects can avoid some of the high costs and delays that come with traditional grid reinforcement. This shows that innovation can come not just from new infrastructure, but also from better planning and smarter use of existing systems.
