Energy Innovation Basecamp - Problem Statements 2026

Theme: Building Better and Faster

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator, Gas Distribution, Gas Transmission (Delete as Appropriate)

What is the problem?

Access to overhead line towers is often slow and costly, creating significant challenges for both routine maintenance and rapid response activities.

• Current access is limited: while some towers have vehicle access, teams often need to walk 2–3 spans to reach them. When there is emergency situation with personnel injury or in customers off supply, then safe access and egress is critical. 

• Emergency response plans are slowed down due to poor accessibility, increasing safety risks and operational delays. 

• Permanent access solutions are rarely implemented during planning stages because of cost and environmental objections. 

As networks expand and climate-driven events increase in frequency, the limitations of current access methods are becoming more acute and costly. Permanent access solutions are rarely implemented during planning stages because of cost and project objectives.

What are we looking for?

We are seeking innovative, practical solutions that enable faster, safer, and more reliable access to overhead line towers across a variety of environments. Solutions should reduce the need for personnel to physically traverse difficult terrain for the last span to reach towers. These can include new access methods, tools, infrastructure, or operational techniques, and should ideally target mid-to-high Technology Readiness Levels (TRL 6-9) with evidence of prior testing or feasibility. Proposals must be capable of scaling across extensive transmission networks and adaptable to different terrain types, such as rocky mountainous terrain, peat bogs, fields or river crossings, improving safety and efficiency. Solutions should either:

1. A) improve physical access (e.g., novel mobility platforms, modular pathways, rapid-deployment access aids); or
   B) enhance remote or alternative access (e.g., drones, robotic systems, hybrid inspection approaches).
   We welcome both standalone technologies and integrated methods that reduce dependency on helicopters and on-foot traversal.

What are the constraints?

Solutions must comply with Comply to ENA standards ENATS 43-8 for OHL clearance and adhere to environmental requirements relevant to transmission assets and land access. They should integrate with existing operational procedures and be deployable without major system downtime. Remote monitoring can be carried out but maintenance needs to be generally done by OHL personnel (working at heights up to 70 meters).

Cost-effectiveness is key, with strong consideration for repeatable deployment and long-term maintenance affordability. Proposals must accommodate varied terrain, weather conditions, and accessibility restrictions, and should not require large permanent infrastructure unless justified by value. Any data-driven solutions must be compatible with existing digital systems and security protocols.

Who are the key players?

Key stakeholders include transmission network owners, asset management, operations teams, landowners, and system planners. SSEN Transmission Operation and safety team.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

This challenge builds on ongoing efforts to improve transmission network resilience, including remote condition monitoring, autonomous inspections, and digital modelling of the network. No previous innovation projects known, but this problem is industry wide issue 

What else do you need to know?

Innovators should consider the operational realities of remote fieldwork, including weather exposure, environmental hazards, protected land, landowner permissions, and the need for rapid mobilisation during faults. Solutions should minimise environmental impact and avoid introducing new safety risks. Consideration of logistics, transport, storage, deployment time, and training requirements is essential for practical adoption. Additional technical information on tower types, terrain categories, and network access processes can be provided as part of an innovation project. Any proposed solution should clearly articulate value, risks, and pathways to pilot deployment.

Download full document here

Theme: Building Better and Faster

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator,

What is the problem?

Dynamic Line Rating (DLR) enhances the utilisation of OHL capacity, however this may be limited by the capacity of other interconnected network assets.  How can we reduce this limitation?

What are we looking for?

There is a need for a baseline understanding of the life of existing transformer assets as a starting point.  This will inform solutions that remove the normal capability limit (NCL) rating limitation of non-OHL assets, to release higher capability of DLR.  The Technology Readiness Level is not limited.  Scalable solutions are sought, for deployment across the network, including automation feature to minimise manual workload.

What are the constraints?

The solution must maximise use of existing data sources and initially avoid addition of new monitoring. 

Phase 1 - Solutions intended to be non-invasive to expedite benefit quicker, minimising addition of active monitoring.

Phase 2 – Longer term solution could be more sophisticated.

Who are the key players?

Key stakeholders are TOs, DNOs, NESO. Consumer benefit (reduced constraint costs), User benefit (higher load factor), Developer benefit (reduced connection costs and/or earlier connections).

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

Builds on Dynamic Line Rating projects for OHL assets, including SSEN-T’s North of Beauly DLR innovation project - Leading the way on dynamic line rating - SSEN Transmission

The System Access Reform initiative, in response to the Electricity Commissioner’s report, frames the importance and context of reducing system operation costs for NESO and the end consumer, whilst simultaneously facilitating network upgrades to achieve Pathway to 2030 objectives.  The DSR project will therefore require collaboration with NESO and will be reliant on a refreshed ratings management system to fully utilise dynamic data for maximum benefit.

Download full document here

Theme: Building Better and Faster

Network Areas: Electricity Transmission

Despite existing safety measures, construction sites remain high-risk environments, with significant risk created by interactions between people and heavy machinery. Current arrangements to manage these risks tend to rely on traditional methods like site setup, physical barriers, supervision, and training. While new technologies exist, there is a significant gap in their widespread adoption, and much of the existing plant and machinery on sites lack helpful safety features like blind-spot detection, automated warnings, or real-time monitoring.

This issue is compounded by an inconsistent approach to the adoption of People-Plant Interface (PPI) safety technologies across major infrastructure projects, such as substation builds, upgrades, and overhead line work. While various technologies are used by different contract partners, there is no standardised process for identifying, trialling, and implementing the most effective, best-in-class solutions. This lack of a unified framework creates a missed opportunity to collectively reduce PPI risk and drive continuous improvement in safety performance.

Within the Pathway to 2030 programme - a significant investment initiative aimed at upgrading the electricity transmission network across Great Britain - a large-scale, multi-project scheme where minimising PPI risk is a strategic priority—the selection and deployment of safety technology can be fragmented. This leads to varying levels of success and prevents the sharing of crucial data and lessons learned. To achieve a step-change in safety, a collaborative approach is needed to systematically evaluate and adopt proven innovations from the global and emerging market.

What are we looking for?

We are seeking innovative solutions and new PPI technologies for trialling and adopting through our collaborative Pathway to 2030 framework in relevant operational settings. We are interested in solutions that have been tested and are at a suitable technology readiness level for operational pilots.

What are the constraints?

• Solutions must be designed to integrate with existing equipment and workflows on complex construction sites.
• The proposed trial methodology must not compromise existing safety standards.
• Technologies must demonstrate results superior to those achieved by other means and be capable of meeting or exceeding current industry benchmarks.
• Solutions should be scalable for potential rollout across multiple projects and contract partner organisations.

Who are the key players?

The key stakeholders for this problem include SSEN-T, contract partner organisations, the wider supply chain, and technology developers/manufacturers. The ultimate beneficiaries are the on-site personnel whose safety will be enhanced. We are looking to attract solutions from technology innovators, safety specialists, and data analysts who can support this collaborative initiative.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

This problem statement is based on a proposal developed by a People Plant Interface (PPI) Working Group as part of the Pathway to 2030 SHW Steering Group. The proposal, PPI Memorandum of Use (MoU), seeks to establish a formal agreement between contract partners to collaborate on trialling and adopting new safety technologies. This initiative builds on the existing structure of the P2030/ASTI schemes and aims to formalise a process for continuous safety improvement.

What else do you need to know?

We envision an initial pilot program to trial distinct PPI technologies across two to three diverse project sites. This pilot will include a 12-week active trial and data collection period. The primary deliverable will be a formal recommendation report for our Steering Group. Innovators should consider this proposed structure in their submissions.

Download full document here

Theme: Flexibility and Forecasting

Network Areas: Whole System

What is the problem?

Artificial intelligence and related technologies (e.g., machine learning) are advancing rapidly and can now solve very complex problems in other industries. For example, Protein Folding in Biochemistry. It seems likely that AI can solve a variety of issues in the energy industry. We have already made progress, and solutions that have been explored are summarised in Table 1 at the end of this document:

While some of these use cases are well developed, many projects and initiatives focus on specific niches. It is not possible to say that the regulated networks are engaged in a coordinated program of research and development leading to holistic, shared solutions.

As we move towards net-zero, the energy network is becoming much more complicated and distributed, combining highly dispersed renewable energy, nuclear and small nuclear reactors, and more traditional base-load generation.  This requires a proliferation of supporting services, including energy storage and energy stability. This needs to be supported by a greatly expanded electricity transmission and distribution network. In addition, the gas network may need to be converted to support the transmission of Hydrogen across the UK, whether on a localised or national level.  This is further complicated by a much more dynamic energy market, where customers are incentivised to manage consumption to balance the load better and reduce constraint costs. The question is whether we are designing and building the optimal energy system with assets in the right locations to achieve affordability and sustainability. Is this type of optimisation problem only solvable through Artificial (General) Intelligence, machine learning and high-powered computing

What are we looking for?

We are looking for proposals for a coordinated research program, or possibly a dedicated research centre or centre of excellence, to answer the question: Can we use Artificial General Intelligence to better design, build, and manage the integrated energy system of the future? 

The AGI should be designed to analyse the problem and generate a set of network design options that minimise cost, minimise use of environmental capital, maximise energy efficiency, and maximise social utility.

How could this research program be coordinated across the entire UK energy network? What are the use cases and problems that should be solved in the journey to solve the problem of designing the most efficient energy network possible? We are interested in both national and regionalised solutions for the UK energy market.

This challenge is very ambitious, but very deliberately so.  This is much more about the big picture optimisation of the UK network.  The ambition is a well-funded R&D institute (like the HVDC Centre) but focused on AI applied to energy systems, funded and supported by the whole energy industry in the UK.

What are the constraints?

We are not looking for a  single niche use case, but more for proposals that will explore the best way to set up a coordinated program of research and development, which will allow agile and rapid growth of new tools. The overall goal should be ambitious, to employ AGI to design the most efficient possible UK network that offers best value for the customer. While ambitious, we should examine how uses cases can be developed that bring more immediate benefits to the consumer while also working towards much mor ambitious tools. ambitious, we should examine how use cases can be developed that bring more immediate benefits to the consumer while also working towards much more

 In this first phase of this project we would like to answer the question:

(1) Do we need a dedicated (well funded)  and shared centre of excellence for the application AI (and other data analytic tools) in Energy Networks? What is the evidence for the recommendation.

(2) If the answer to (1) is, what are the options and models for setting up a centre of excellence? How should any centre of excellence be governed.

(3) Who should be involved in any proposed centre of excellence?

(4) What can we learn from other industries, and what would be best practice for agile use case development that can be shared and adopted by all energy networks in the UK?

(5) How can the UK benefit (in terms of general economic growth) from a dedicated centre of excellence?

(6) What level of funding is required to make a centre of excellence work?

Who are the key players?

The key players are all the regulated energy networks, energy developers, and experts in the application of AGI and Machine Learning, and in the use of high-powered computing. We are interested in collaborative proposals that involve partnerships among networks, academia, research institutes, and experts in AGI and high-performance computing. We would welcome proposals from private and public research institutes and consider part-funding a dedicated research program

.
There is also a research consortium, mainly USA based under EPRI:  EPRI’s Open Power AI Consortium (OPAI)—its mission, participants, capabilities, recent updates, and workstreams: [msites.epri.com], [restservice.epri.com], [restservice.epri.com].  Proposals should consider how to best existing programs of research from around the world.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

Many niche AI and machine learning use cases are being developed. These can easily be found on the ENA Smarter Networks Portal or on the Networks own innovation web pages.  However, we are not aware of a dedicated and well-funded program of research to design, build and manage the optimal energy network. There are also multiple research programs globally.  Consideration should be given to collaboration with other research programs while also considering whether or not the UK and UK based companies and develop a competitive edge through unique capabilities available in the UK applied to specific case of the UK energy system.

What else do you need to know?

Please research the use of AI in networks, but focus on the general and ambitious problem of using AGI to design and build the most efficient energy network in the world.

Download full document here

Theme: Flexibility and Forecasting

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator

What is the problem?

What is the wider context of the problem described above? Are there any specific details to expand on? If the problem statement is phrased as a question, this section may end by posing that question back to the innovator.

Optimisation of system design and operation of remote islands in the face of climate threats is an area that needs careful attention. Operating parts of the electricity networks as remote islands with significant renewable penetration presents unique challenges in balancing supply and demand, maintaining system stability, and ensuring reliability. However, if these challenges can be overcome, the option of island or microgrid operation could unlock greater resilience for remote areas of the network. Given the current restrictions on island operations, there is a real opportunity for innovation on this topic, using islands with significant renewables as a testbed for potential wider rollout.

What are we looking for?

What kind of solution do you want? What TRL are you looking for? Does the solution need to be operable at scale? Are you looking specifically for methods and techniques? Does the idea need to have been tested to a certain extent already? There may be A) and B) sections if there is a wider issue with different types of solutions being sought.

We are seeking solutions that enable detailed modelling of various grid reinforcement scenarios aimed at improving island grid resilience and supporting islanded operation. These solutions should incorporate innovative grid control and management mechanisms and compare alternative reinforcement approaches against standard transmission reinforcement options. The comparison should include cost implications and assess compliance with relevant grid legislation and regulatory requirements.

What are the constraints?

These might include “the solution must…” type responses (e.g., compliance with certain regulations, existing software, methodology or technology - or technology agnostic - applicability to specific networks, budgetary requirements, needing to be rolled out within a specific timespan…)

Ideally the solution utilises software that is familiar to the Transmission Owners and is interoperable with other network power modelling packages. The solution should be compliant with grid legislation requirements.

Who are the key players?

Who are the key stakeholders affected by this problem statement? Who will adopt this solution? Who benefits from the resolution? What sort of innovators are you trying to attract solutions from? Who is the target market for this problem statement?

The key stakeholders are the Transmission Owners, Distribution Network Operators, the NESO, and renewables developers with the main users being the network owners and operators responsible for grid compliance and management. Beneficiaries would include local communities, the regulator and wider energy system. The innovators would be expected to have expertise in grid stability modelling and be able to investigate island/microgrid operation and its impact on stability.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

What are the links to previous or ongoing work? Where possible, please provide links to the SNP, individual pages on network websites describing similar work, etc. Are there any current or future dependencies? Are there any other enablers that innovators should reference or specifically build on in their proposals? Are there any solutions which have already been considered / trialled?

This aligns with UK decarbonisation target and previous innovation project focused on modelling system flexibility and design particularly at a transmission level.

What else do you need to know?

Use this space to add anything else that an innovator would need to know to submit a submission to this problem statement. This may be additional context on the issue, additional sources of information, additional information about your network’s processes, or any additional enablers and constraints.

Download full document here

Theme: Flexibility and Forecasting

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator,

What is the problem?

Network access for planned outages affecting GSPs can be onerous to agree due to risk-averse outage planning, as TOs and DNOs seek to maximise their ENS and IIS incentives respectively, in response to consistent stakeholder feedback.  The status of the assets which remain in-service during the planned outage may not be routinely considered in detail.  On balance, Emergency Return To Service (ERTS) measures may be unnecessarily extensive and costly for low probability events.

What are we looking for?

Several factors can affect the likelihood of a fault occurring during a planned outage affecting a given GSP, some of which may not currently be considered in demand risk assessments for planned outages.  Solutions should utilise existing data sources to provide a probabilistic demand risk assessment for planned outages.  This will inform efficient risk mitigation requirements for a given outage or outage combination.  Solutions should be scalable for use at a given GSP or combinations of GSPs.

What are the constraints?

The solution must not significantly diminish asset life.  Minimal disruption to existing network assets is preferred, utilising existing data sources instead to deliver value quicker.  Loss of supply likelihood and impact must be clearly articulated by the solution in each instance, including the logic behind the figures, for key stakeholders to make an informed decision.

Who are the key players?

Key players are TOs, DNOs, DSOs, NESO, sensitive customers.  TO benefit (efficient delivery of construction and asset replacement portfolio), DNO benefit (reduced period of demand at risk), Consumer benefit (reduced disruption to embedded renewable generation), Developer benefit (faster connections).  Collaboration with DNOs is critical to the success of solutions.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

The problem statement recognises the ongoing conflict of network access affecting GSPs versus reliability of supply, exacerbated by the requirement to deliver increasing construction, asset replacement and maintenance portfolios.

What else do you need to know?

Use this space to add anything else that an innovator would need to know to submit a submission to this problem statement. This may be additional context on the issue, additional sources of information, additional information about your network’s processes, or any additional enablers and constraints.

Download full document here

Theme: Flexibility and Forecasting

Network Areas: Electricity Distribution

What is the problem?

The current process to locate a UG LV fault typically begins by analysing the TDR (Time Domain Reflectometer) readings at the LV substation (having confirmed via a Fusemate that the fault is not transient or due to a blown fuse). An impedance trace can be used to find the approximate distance to fault – however, there are typically multiple branching paths in an interconnected network that may fit this distance. From here, a sniffer device is used to find an approximate location – however this is slow, imprecise, and requires drilling into the ground to measure for gas emissions.

For MV and HV faults, more precise devices are used – these use a surge generator to send high voltage pulses through the cables, allowing the on-site engineers to ‘listen’ for an audible signal using a specialised receiver when this surge hits the cable fault (commonly called ‘thumping’). However, a DNO’s LV network (230/400V) does not currently have a similar device that can quickly and safely be used to locate a cable fault location.

What are we looking for?

A portable unit that can be used to quickly and precisely locate LV UG Faults. This may look like a portable surge generator unit and receiver device powerful enough to produce and detect an audible response from any LV cable fault, but that will not risk damaging any customer property or blowing the fuses in any connected substation.

This should be capable of connecting to a LV fuse board within a substation, and potentially an LV linkbox. Any connections to the network should be secure and ideally lockable.

A – A portable surge generator and receiver device that can be connected to an LV board or linkbox.

B – A portable surge generator and receiver device that can only be used on an LV board.

C – Any solution that allows quick location of LV UG faults once an impedance trace has been run without the need to drill/use a sniffer device (not necessarily using a surge generator/receiver).

What are the constraints?

Any solution must be safe to use on LV networks (230/400V) and not pose a risk of damage to customer property.

Any solution must comply with ESQCR regulations.

If the solution is designed to be installed on an LV Board, it must be adaptable to fit 82mm and 92mm fuse stalks.

The solution must also be secure when connected to the network whether on a LV fuse board, Linkbox, or other connection points – this connection must be unable to slip (i.e. clips) and should be lockable.

Who are the key players?

District engineers involved in LV fault finding and LV Jointers will be the key users who will adopt this solution and use any tool developed.

Any innovators who have experience in surge generators or devices to monitor the LV network would be the target market for this problem statement [(i.e. Megger EZ Thump, EA Alvins, Camlin Bidoyngs, Eneida monitors)].

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

SPEN currently has LV monitors and recloser devices that can be used to provide impedances and estimated distance to fault. There is also an established process for LV UG fault location, as detailed in the first section of this document. Any device developed would need to provide greater accuracy and faster restoration times than these existing methods.

What else do you need to know?

When fixed to an LV board, the device must fit 82 and 92mm stalks. As, depending on the final unit, the unit may be used by a lone worker and may be left live, it should be able to be securely connected (preferably with lockable connection points) within a substation (this unit would not be left unsupervised in a linkbox or other connection point outside of a lockable LV Substation).

Any solution should function for multiple cable sizes (0.1cu, 0.2cu, 95wf, 185wf, up to 300mm2), across 3 core and 4 core cables.

While safety measures can be built into procedure around the device, any inbuilt safety mechanism or procedure validation would be desirable.

Download full document here

Theme: Flexibility and Forecasting

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator,

What is the problem?

Current control system validation relies heavily on RTDS Replica setups, which can be resource-intensive and may not fully capture the complexity of modern converter-based systems. With the introduction of GTSOC offering FPGA-based high-speed processing and secure integration of vendor-specific controls, there is uncertainty about whether this technology can replace or complement RTDS Replica for real-time simulation and testing.

The energy system is evolving with increased penetration of HVDC, FACTS, and renewable generation, requiring advanced simulation tools for stability and protection studies. Traditional RTDS Replica systems have limitations in scalability, cost, and integration complexity. GTSOC promises enhanced fidelity and black-box vendor model integration, but its comparative performance and operational benefits remain unclear. Key question: Can GTSOC V2 deliver a more efficient, secure, and scalable solution for control system validation compared to RTDS Replica?

What are we looking for?

• A clear benchmarking framework comparing RTDS GTSOC and RTDS Replica in terms of:
• Real-time performance and fidelity
• Integration complexity
• Cost-effectiveness and scalability
• Cybersecurity and IP protection
• Technology Readiness Level (TRL): Minimum TRL 7 (validated in lab environment, ready for pilot testing), reflecting that prototype testing is expected, especially given prior system-level testing.
• Practical Plan:

1. Complete system-level testing of the replica solution.
2. Update and adapt the base code for new applications or requirements as they arise.
3. Compare performance and integration through Factory Acceptance Testing (FAT) or equivalent processes.
4. Where possible, leverage earlier tested versions for benchmarking and code updates.
5. Ensure sufficient hardware resources are available and include any additional licensing or infrastructure costs as needed.

• Solutions should be scalable and adaptable across transmission and system operator environments.

What are the constraints?

• Should integrate with existing RTDS hardware/software.
• Deployment within Energy Innovation Basecamp timelines (2026).

Who are the key players?

• Stakeholders: Electricity Transmission Operators, System Operators, RTDS Technologies, OEMs for converter controls.
• Beneficiaries: Network operators, system planners, and protection engineers.
• Innovators sought: Simulation technology developers, academic research teams, OEMs.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

Yes:Builds on RTDS-based simulation environments already deployed in UK networks.
GTSOC V2 documentation: https://knowledge.rtds.com/hc/en-us/articles/7817390306199-GTSOC-V2-Multi-Function-Auxiliary-Simulation-Hardware

What else do you need to know?

- Should consider IP protection mechanisms for vendor-specific models.
- Solutions should address future scalability

Download full document here

Theme: Maximising Use of Existing Infrastructure

Network Areas: Electricity Distribution and Electricity Transmission

What is the problem?

A Risk Management Hazard Zone (RMHZ) is established when an electricity asset is suspected to have a defect that could result in a catastrophic failure. A RMHZ limits the activities and duration operational staff can be in the zone. These RMHZs can vary in size dependent on the consequences of failure. If multiple assets are installed in a Grid or Primary substation then these RMHZs will overlap covering most of the area within the compound.

The problem we have is that weeds continue to grow throughout the year and need to be kept under control.  Uncontrolled growth of weeds such as Buddleia and bindweed can become a hazard in a substation for staff needing to enter the compound. All network operators have a responsibility for the safe access by technical and maintenance staff.

In substations with large shingle compounds covered by a RMHZ vegetation management cannot be permitted to be carried out.

What are we looking for?

UK Power Networks is looking for an automated method to keep vegetation under control.  The device should be able to move across the compound cutting down vegetation and apply weedkiller to prevent regrowth. We would like to set the device up and leave it for a few days and recover it and deploy it elsewhere.

What are the constraints?

Substation compounds are outdoors so the device must be able to operate in any weather conditions.

The surface of a compound is shingle, but there are also concrete paths that could be considered obstacles needing to be avoided.

The device will be unattended so it will need to: self-navigate the compound avoiding collisions with equipment; dispense weedkiller; report areas it has not been able to access; and recharge when necessary.

The device must be light enough to allow it to be transferred from one substation to another. It could be transported on a trailer.

Who are the key players?

The key stakeholders affected are staff responsible for operation and maintenance of substations.  Operational safety teams will also be important stakeholders.  The solution will be adopted by the maintenance team. This solution will provide safety benefits by controlling weeds even when RMHZs are in place. We are trying to attract innovators who work with autonomous machines. The target market are the network operators who have outdoor compounds that need vegetation to be controlled.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

This problem statement is new.  This project must allow staff to continue to work safely and comply with Distribution Safety Rules.  Any solution will need to be approved by stakeholders within the company.

What else do you need to know?

N/A

Download full document here

Theme: Maximising Use of Existing Infrastructure

Network Areas: Electricity Distribution

What is the problem?

Surge arrestors are used at the interface between underground cables and overhead lines where it is necessary to protect the underground cable from over-voltages caused by lightning and switching surges. There are various designs of surge arrestors on distribution networks ranging from legacy porcelain to Gapless Metal-Oxide Polymeric designs. If a surge arrestor fails it may cause a supply interruption. Porcelain surge arrestors have been known to shatter.

What are we looking for?

UK Power Networks is looking for a solution that allows the condition of the surge arrestor connected to 11kV networks to be assessed without having a pre-arranged interruption. 

At 33kV and 132kV tests could be carried out as part of a planned outage.  A different method of assessment could be considered.

What are the constraints?

The solution must be suitable for use outdoors in different weather conditions.

Application of higher test voltages is not acceptable for 11kV assessments.

The test must be of short duration as there is a risk that the surge arrestor may not be in a good condition.

Who are the key players?

Asset Management’s Inspection and Maintenance team.

Operational staff involved in maintenance.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

There is a possibility that NGET’s Surge Arrestor Health Assessment by monitoring partial discharge (SAHARA) NIA2_NGET0040 may provide insights to possible solutions.

What else do you need to know?

N/A

Download full document here

Theme: Maximise the use of existing infrastructure

Network Areas: Electricity Distribution, Electricity Transmission

What is the problem?

FFCs are present throughout Great Britain (GB) distribution networks as legacy assets. They are insulated with a layer of cellulosic paper (or PPLP) impregnated with an insulating low viscosity dielectric oil, such as dodecylbenzene or T3788. To prevent void formation the cable is held under a positive fluid pressure (typically between 3-8 bar); as a result, any damage to the cable sheath or accessories will result in fluid leaking into the surrounding environment. This has an impact on the environment as well as asset integrity. Although the lost fluid can be replaced, leaks represent an environmental hazard, particularly if the cable is sited within an environmentally sensitive region or close to groundwater. In cases where an FFC is located close to groundwater, the leaks may also cause environmental contamination which is of concern to the public, water authorities, and the Environment Agency that could enforce the closure of cable circuits or impose limits on their operation. As the FFC network ages further, it is anticipated that the severity of the leaks will worsen due to continued ageing and degradation of the cable sheaths and joints.

While network operators have implemented monitoring, leak detection, and containment measures, current mitigation approaches are reactive and do not address the root cause: the continued reliance on oil-based insulation systems. Full cable replacement is technically effective but often prohibitively expensive, disruptive, and resource-intensive, particularly in densely populated or environmentally sensitive areas.

What are we looking for?

How might we retrofit existing fluid-filled cables to eliminate or neutralise their dependence on oil, while maintaining electrical performance, reliability, and safety, at a lower cost and with less disruption than full replacement?

Developing such a retrofit solution /process could transform environmental risk management for legacy underground cables, reduce pollution incidents to zero, and accelerate progress towards net-zero environmental harm across the electricity networks not just in the UK but globally.

There are multiple factors that require innovation/research with respect to:

1. the technique of retrofitting
2. A chemical with appropriate physical and chemical properties to replace the oil; and
3. Consideration of cost benefit analysis for points 1 and 2.

What are the constraints?

Ideally the solution would remove all fluid from the cable and reduce environmental risk to zero. The solution must maintain electrical integrity and rating of the cable to the same level as the FFC. Access to the cable would only be at existing fluid pumping points and should remove risk along entire hydraulic sections. The solution would ideally work across all cable voltages, types and materials.

Who are the key players?

• The key stakeholders are the energy network operators, Environment Agency, Ofgem, and society and nature at large.
• It will be adopted by the energy network operators in the UK and potentially further afield.
• If it is managed, this will reduce oil seeping into the ecosystem from FFCs leakage. This will benefit society and nature at large. It will remove a environmental pollutant from legacy assets.
• We are looking for any type of innovator who can solve this complex issue.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

The parts of the networks which have FFCs.

What else do you need to know?

There is the FFCs section of the ENA website which may be useful https://www.energynetworks.org/work/environment

Also, DNO and TO’s AERs.

Download full document here

Theme: Maximising the use of existing infrastructure

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator,

What is the problem?

The growing share of volatile, fluctuating renewable generation has placed additional demands on the transmission networks, resulting in an increase in grid congestion. The cost of balancing services required to manage constraints and maintain grid stability has risen substantially, directly impacting consumers.

NESO currently uses manual Network Topology Optimisation (NTO) to help manage constraints. NTO is a continuous process of using transmission system assets to alter the electrical flow from generation to demand. The more efficiently the system can run, the fewer balancing actions are required and therefore the cost of balancing actions can significantly reduce.

A recent NIA funded project identified that although automation techniques have been developed to solve thermal constraint optimisation problems, voltage and stability optimisation algorithms are less advanced and currently not fit for purpose for an operational environment, restricting the automation of analysis of more complex power system constraints.

How can we develop scalable voltage and stability optimisation algorithms to enable future automation of NTO processes?

What are we looking for?

We are looking for new methods and techniques that improve optimisation algorithms that can be used for determining voltage and stability power system limitations on the transmission network.  This can be delivered either as research, or as a tested product.

What are the constraints?

The solution must have the potential to work with network planning tools (e.g. Powerfactory), either in their existing format, or through future development to those tools.

Who are the key players?

Direct stakeholders: NESO and other System Operators globally, DSOs.

We are ideally looking to work with research institutes, universities and companies interested in complex power system research.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

This builds on the NIA funded report into Network Topology Optimisation (NIA2_NESO087) which highlights voltage and stability optimisation algorithms as a key area to advance in order to achieve automation of NTO.

What else do you need to know?

N/A

Download full document here

Theme: Maximising the use of existing infrastructure

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator,

What is the problem?

The growing share of volatile, fluctuating renewable generation has placed additional demands on the transmission networks, resulting in an increase in grid congestion. The cost of balancing services required to manage constraints and maintain grid stability has risen substantially, directly impacting consumers.

NESO currently uses manual Network Topology Optimisation (NTO) to help manage constraints. NTO is a continuous process of using transmission system assets to alter the electrical flow from generation to demand. The more efficiently the system can run, the fewer balancing actions are required and therefore the cost of balancing actions can significantly reduce.

As we begin to automate the process of NTO, the speed in which load flow solvers can operate is becoming a limiting factor in the number of scenarios that can be considered.  A recent innovation project has identified that while techniques have been developed that enables rapid DC analysis of scenarios, AC load flow algorithms remain slower and more complex, restricting analysis of more complex power system constraints.

How can we advance the development of AC load flow solvers to enable automation of our NTO processes?

What are we looking for?

We are looking for new methods and techniques to improve the speed in which AC load flow solvers can function.  This can be delivered either as research, or as a tested product.

What are the constraints?

The solution must have the potential to work with network planning tools (e.g. Powerfactory), either in their existing format, or through future development to those tools.

Who are the key players?

Direct stakeholders: NESO and other System Operators globally, DSOs.

Indirect stakeholders: Any user of network analysis tools that use AC Load Flow Solvers.

We are ideally looking to work with research institutes, universities and companies interested in power system research.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

This builds on the NIA funded report into Network Topology Optimisation (NIA2_NESO087) which highlights the speed of AC Load Flow Solvers as a key area to advance in order to achieve automation of NTO.

What else do you need to know?

N/A

Download full document here

Theme: Net Zero Transition Impacts

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator, Gas Distribution, Gas Transmission (Delete as Appropriate)

What is the problem?

The construction of permanent and temporary access roads for electricity transmission and distribution projects is a critical requirement for enabling the transportation of heavy equipment, materials, and personnel to remote or challenging sites. However, the current approach relies heavily on large quantities of quarried stone, which presents several significant challenges:

• High Embedded Carbon: The extraction, processing, and transportation of stone contribute substantially to greenhouse gas emissions, increasing the overall carbon footprint of infrastructure projects.
• Environmental Impact: Stone-based construction methods often disturb sensitive ecosystems, particularly in areas with peatland or other fragile ground conditions. Peatlands are vital carbon sinks, and their disruption can release stored carbon, undermining climate goals.
• Cost and Resource Intensity: Procuring and transporting stone to remote locations is expensive and logistically complex, especially when projects span large geographical areas.
• Limited Sustainability: Traditional methods do not align with industry commitments to achieve net-zero carbon targets and reduce environmental impact across the lifecycle of assets.

These challenges are amplified in regions with difficult terrain, such as peat or soft soils, where conventional stone-based solutions require even greater material volumes to ensure stability and load-bearing capacity. This results in higher costs, longer construction times, and increased ecological disruption.

What are we looking for?

Solutions being sought should demonstrate innovation and seek to:

• Minimise stone usage in access track construction.
• Show viability for multiple ground conditions, including peat.
• Maintain structural integrity and safety for heavy plant and vehicles.

The solution would aim to achieve TRL in the range 5 to 7 (demonstrated in relevant environment) although earlier-stage ideas with strong potential are welcome.

Solutions should:

• Have the potential to be scalable for Large Capital Projects (LCPs).
• Demonstrate environmental benefits and cost-effectiveness against agreed metrics.
• Ensure that any methods, materials, or design approaches can be integrated with existing construction practices and comply with key building regulations.

What are the constraints?

The solution should be able to:

• Comply with health, safety, and environmental regulations.
• Support heavy load-bearing requirements for construction traffic.
• Avoid introducing significant additional costs or complexity and demonstrate a reduced carbon footprint.

Who are the key players?

The key stakeholders would be the transmission and distribution network owners and their civil supply chain partners. The adopters would be the network operators and Large Capital Project (LCP) delivery teams. Beneficiaries would be the local community, environment and Ofgem. To deliver this technology, innovators with expertise/experience with civil engineering, materials development and sustainability specialists.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

Any links with previous innovation projects focused on low carbon construction should be identified and reviewed to build upon their learnings were possible without restriction.

What else do you need to know?

Solutions must be compliant with industry standards for temporary and access roads. Integration with existing supply chain and construction processes is desirable but not essential. A life cycle analysis of the carbon footprint for the proposed solution is recommended.

Download full document here

Theme: Net Zero Transition Impacts

Network Areas: Electricity Distribution, Electricity Transmission, Electricity System Operator,

What is the problem?

The control room operator must visualise a growing number of power system characteristics as we move towards a decarbonised electricity system, including inertia, system strength and system oscillations, on a more regular basis.  In addition to this, new levels of automation, such as Network Topology Optimisation, will stream a significantly increased volume of options to each operator as scenarios become more varied throughout any given day.

Much of this information is currently displayed using traditional methods such as graphs and tables, which can be difficult to fully interpret in operational timescales and require significant experience to bring these data sources together. As the volume of data expands, along with the complexity of operational issues, we need to ensure that control room engineers can identify the critical information to maintain the system integrity.

We would like to understand how we effectively visualise the extensive data generated by the transmission network to ensure control room engineers are able to make optimal decisions in a timely manner?

What are we looking for?

We are looking for research into new design principles that can be used in our control room operator products to best visualise the following:

• Inertia
• Oscillations
• System Strength
• Network Topology Optimisation output

What are the constraints?

None

Who are the key players?

Direct stakeholders: NESO and other System Operators globally, TOs, DSOs/DNOs.

Indirect stakeholders: Any user of real-time power system products.

We are ideally looking to work with research institutes, universities and companies interested in human machine interface research.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

This builds on the NIA funded report into Network Topology Optimisation (NIA2_NESO087) which highlights the need to consider enhancements to the operator user interface as a key area in order to achieve automation of NTO.

This also builds on the NIA funded report by Kings College London into visualisation techniques to improve the NESO videowall interface in the Electricity National Control Centre (NIA2_NESO073).

What else do you need to know?

N/A

Download full document here

Theme: Net zero transition impacts

Network Areas: National Energy System Operator

What is the problem?

To date, NESO procurement of stability services has focused on assets that are transmission-connected, or if embedded, connected at 132kV only. Consequently, NESO is not currently procuring stability services from distribution-connected assets at the DNO level (specifically <132kV). There are concerns about the effectiveness of these distribution-assets in providing stability services and potential conflicts with equipment on the distribution network.  Before procuring stability from distribution-connected assets, NESO need to understand the capability of these assets and their ability to provide stability services.  

What are we looking for?

In 2023, NESO launched the first tender under the Mid-Term (Y-1) Stability Market to procure stability services. The primary goal of this market was to access inertia capability from existing assets on a high-availability basis. By offering annual contracts, the market provides revenue certainty for participants while reducing risk for NESO, especially as periods of low inertia become more frequent and unpredictable. The first contracts for the Mid-term (Y-1) Stability Market have been awarded and run from October 2025 to September 2026. NESO have since launched the second tender under the Mid-term (Y-1) Stability Market In October 2024 and launched the first tender under the Long-term Stability Market in March 2025.

The stability market is currently seeking provision of stability services from assets that are transmission-connected, or if embedded, connected at 132kV only. In this project we aim to understand the potential of distribution-connected assets to contribute to system stability. Specifically, we would like to understand their effectiveness towards system stability, and we would also like to understand any technical barriers that could be faced when using distribution-connected assets in meeting stability requirements. Ultimately, this will allow NESO to decide whether, based on the findings of this innovation project, if it is appropriate to expand the Stability Markets to procure from distribution-connected assets <132kV.

What are the constraints?

1. Technical effectiveness of distribution-connected assets in providing stability services.
2. Potential conflicts with equipment on the distribution network.
3. The need to explore and understand internal and external factors or technical limitations that may hinder access to these services.

Who are the key players?

1. NESO (National Energy System Operator)
2. Distribution Network Operators (DNOs)
3. Providers of stability services from distribution-connected assets
4. Industry stakeholders providing feedback

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

Yes, it builds on the existing Stability Pathfinders  and involves potential developments in the Stability Market. The project aims to explore existing infrastructure and policy decisions related to accessing stability services from distribution-connected assets.

What else do you need to know?

1. Specific technical challenges or limitations associated with the provision of stability services by distribution-connected assets
2. DNO views on the use of distribution-connected assets by NESO for provision of stability services, and how instructions for provision of service can be facilitated
3. Criteria for assessing the effectiveness of stability services from these distribution-connected assets and how DNOs could provide this information to NESO on a sufficiently regular basis.
4. Any existing policies or regulations that may impact the use of distribution-connected assets in the Stability Market or any other markets.
5. As a secondary piece, detailed feedback from the industry regarding the use of distribution-connected assets to provide stability services

Download full document here

Theme: Net zero and the energy system transition

Network Areas: Gas Distribution, Electricity Distribution and Electricity System Operator

What is the problem?

Multi-occupant buildings (e.g., flats, apartments, mixed-use developments) face significant challenges in reducing carbon emissions due to shared heating systems, diverse energy needs, and split incentives between landlords and tenants. Current solutions often focus on single-family homes, leaving a gap for scalable approaches in multi-occupant settings.

In the UK energy networks are struggling to provide affordable and equitable options for MOBs to decarbonise. This stems from the high reinforcement needs per building, replacing gas with electrical heating will often increase the electrical load, necessitating upgrades for the internal and external network infrastructure. Often far costlier than single homes, the same goes for reinforcing existing gas assets in the building with some parts of the internal pipe work being more prone to require repairs than a standard single property. Another one of the big issues is the structure of the ownership for these types of buildings, with complex structures involving housing associations, private owned and rented accommodation as the most common. This causes issues when it comes to decision making but also for the cost sharing, with many buildings having a lack of maintenance due to difficulties in assigning responsible parties.

The UK’s net-zero targets require rapid decarbonisation of heat and energy systems. Multi-occupant buildings represent a large proportion of urban housing stock and commercial spaces. Solutions must address technical, economic, and behavioural barriers while ensuring affordability and minimal disruption.

What are we looking for?

• Innovative technologies, business models, or operational strategies for decarbonising shared energy systems.
• TRL 3–5
• Solutions that can scale across different building types and regions.
• Approaches that integrate with existing infrastructure or enable hybrid systems (e.g., hydrogen-ready boilers, heat pumps, district heating).

What are the constraints?

• Solutions must comply with UK building and energy regulations.
• Cost-effective for landlords, tenants, GDNs, DNOs .
• Minimal disruption during installation.
• Compatible with existing metering and billing systems.

Who are the key players?

Building owners, housing associations, energy shippers, technology providers, local authorities, DNOs, GDNs.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

• Smarter Networks Portal – Heat Decarbonisation Projects
• Previous ENA projects on hybrid heating and shared energy systems.

What else do you need to know?

• Consider occupant engagement strategies.
• Highlight carbon savings and cost-benefit analysis.

Download full document here

Theme: Net zero and energy system transition

Network Areas: Gas Distribution, Electricity Distribution, Electricity System Operator

What is the problem?

Achieving net zero requires coordinated transition across the whole energy system. It requires giving customers viable, affordable and resilient choices for decarbonising heat. Whether households adopt green gas, electrification, hybrid systems or an alternative gas supply each pathway has a distinct implication for electricity and gas networks that must be understood and mapped. Understanding how hydrogen switchover reshapes electricity demand is critical to ensuring resilient, affordable, and equitable decarbonisation.

The transition to hydrogen in industrial and commercial (I&C) sectors will reshape energy demand profiles. The problem is that network operators currently lack clear visibility of where and how hydrogen switch‑over will occur, and what the net impact on electricity networks will be. Identifying and mapping where this switchover (some or all gas pipelines supplying domestic customers) may occur will impact future planning grid reinforcement, flexibility services, and investment pathways.

The key questions:

• How will hydrogen adoption in I&C sectors reshape electricity demand profiles, and where will these impacts be most concentrated?
• How will a change in gas supply effect current domestic gas users? What are their options? Are these geographically limited? Considering just transition requirements.

What are we looking for?

Solution(s) may include:

• Analytical tool and modelling single integrated approaches to quantify and map electricity demand impacts and reinforcement needs under different hydrogen adoption scenarios.
• Customer and stakeholder insights including studies, reviews, reports that capture customer pathway preference and behaviours or that show possibilities in different regions or scenarios that are specific to that area.
• Business models and operational strategies including innovative tariffs, incentive, or operation playbooks to manage transitional demand shifts and coordinate conversion schedules.
• This list is not exhaustive, and the scope is deliberately open to attract novel technical, social, regulatory or market-based approaches.

Solution expectations:

• TRL:  3–4 considered if novel insights are offered.
• Scalability: Must be operable at regional or national scale.
• Testing: Solutions should have been validated to some extent, either through pilots, modelling, or case studies.

What are the constraints?

• Uncertainty management: The solution must quantify ranges, scenarios, and confidence levels, not single-point forecasts.

(UK heat decarbonization is unsettled at local levels; hydrogen for domestic heating remains uncertain, while electrification is advancing. Some zones may trial or adopt hydrogen; others will not. Solutions must handle multiple policy pathways and reversibility.)

• Regulatory Compliance:  The solution must comply with UK energy regulations, and align with Ofgem reporting, privacy laws, cybersecurity standards, funding and relevant safety frameworks.
• Technology: Be compatible with existing electricity network planning methodologies. Technology-agnostic that can reflect hydrogen, electrification, and hybrid scenarios; no single-path bias.

• Timeline: Provide pilot-ready capability within 6–12 months; scalable deployment plan within 12–24 months.
• Budgetary discipline: Modular delivery with clear milestones, enabling staged approvals

Who are the key players?

Key Stakeholders:

• Electricity networks (adopters): UK Distribution Network Operators (DNOs) and transmission planners—asset managers, network strategy, system planning, flexibility procurement teams.
• Gas networks: Regional GDNs coordinating conversion plans and customer transitions.
• Government and regulators: DESNZ, Ofgem, HSE—policy oversight, funding alignment, safety.
• Local stakeholders: Local authorities, combined authorities, housing associations—execution partners and community engagement.

Adopters:

• • Network operators.

Beneficiaries:

• • Energy networks (better planning, risk reduction), businesses (clarity on energy costs), policymakers (progress toward net zero), customers (reliability, affordability), regulators (evidence-based decisions), and communities (coordinated transitions).

Innovators sought:

• • All with relevant experience, knowledge and understanding.

Does this problem statement build on existing or anticipated infrastructure, policy decisions, or previous innovation projects?

• Build on:
• Smart meter data, EPC ratings, building archetype libraries and LV visibility project led by DNOs.
• Gas network hydrogen conversion planning and neighbourhood pilots (e.g., H100 Fife, East Coast Hydrogen).
• Local authority heat decarbonisation strategies and community energy planning.
• Relevant trials and insights:
• H100 Fife and Gateshead hydrogen homes pilots (appliance conversion, customer engagement).
• Hydrogen Technical & Safety Case projects (Cadent/SGN) providing evidence for domestic use.
• Customer engagement studies on heating preferences, willingness to adopt hydrogen, and barriers to uptake.
• Future dependencies:
• Certification and rollout of hydrogen‑ready appliances.
• Policy decisions on domestic hydrogen and customer choice frameworks.
• Improved smart meter granularity and LV monitoring for real‑time impact measurement.
• Community engagement processes to support vulnerable customers.

What else do you need to know?

Download full document here