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.

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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.

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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.

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What is the problem?

Asbestos-containing materials (ACMs) are widespread in older Multi-Occupancy Buildings (MOBs). Their presence prevents safe drilling or riser modification, causing delays, increased cost, and inconsistent safety assessment that creates disruption for customers. SGN must inspect and maintain approximately 62,000 risers, many of which are located in buildings containing ACMs in stairwells, service risers, cupboards, or service ducts.

A large proportion of these buildings have incomplete, outdated, or inaccessible asbestos records, which means SGN often cannot confirm the presence, type, or condition of ACMs before arriving on site. Current working practices require intrusive asbestos surveys, which introduce long delays—particularly when access arrangements are complex or when specialist licensed contractors are needed.

There is currently no effective, scalable method for rapid ACM identification, risk scoring or low-disturbance riser installation. Without innovation, asbestos will remain a major constraint to SGN’s ability to upgrade risers at pace.

What are we looking for?

We are seeking innovative solutions that enable SGN to safely identify, assess and work around asbestos-containing materials during riser installation or modification, without causing delay, excessive cost or customer disruption. Ideas could evolve around :

• Asbestos risk prediction based on building age + records
• Unified asbestos information-sharing platform with local authorities.
• Non-intrusive drilling or fixings suitable for ACM substrate.
• Remote sensing or imaging to identify ACMs before entry.

What are the constraints?

All solutions must comply fully with HSE asbestos regulations and SGN’s safety case requirements , recognising that building asbestos documentation is often incomplete, inconsistent or unavailable. Innovators must account for highly variable building conditions, including confined riser routes, narrow voids, limited stairwell access, and the presence of concealed ACMs behind boards or ducting. Any proposed approach must minimise disturbance to asbestos, avoid creating new safety risks, and operate effectively in buildings where access is restricted by residents, housing associations or building layout.

Who are the key players?

SGN Network Asset, Mob and operations team, HSE, local authorities, housing associations, asbestos consultants, universities developing new materials / imaging, technology providers.

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

HSE Asbestos Regulations (CAR 2012) impose strict controls on disturbance of ACMs during utility work, significantly impacting SGN’s ability to complete planned riser upgrades.

Grenfell Inquiry recommendations and UK Government policy require enhanced risk assessment and safety interventions in high-rise and MOB housing.

What else do you need to know?

SGN operates approx 62,000 risers  with many of our older MOBs contain ACMs in stairwells, service risers and ducting.

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What is the problem?

Cross-road service replacements are among the most complex, disruptive and costly activities undertaken by gas distribution networks. Traditional open-cut excavation across roads requires multiple teams, extensive traffic management, lengthy reinstatement and coordination with local authorities, resulting in high costs, programme delays and significant disruption to the public.

As network activity increases during GD3 — including service replacement, bulk works and reinforcement programmes — the volume of cross-road interventions will rise. Current approaches struggle to scale efficiently due to limited trenchless options for short spans, poor visibility of existing asset routes, and disconnected processes between design, permitting, delivery and reinstatement.

Without innovation, cross-road service replacements will continue to be a constraint on public disruption

What are we looking for?

We are seeking innovative, scalable solutions that enable gas networks to replace cross-road services more efficiently, safely and with less disruption.

Solutions may include (but are not limited to):

• Short-span trenchless or guided bore technologies suitable for road crossings
• Integrated site apps for real-time cost, reinstatement and progress tracking
• New methods for shared excavation and reinstatement with other utilities
• Advanced subsurface mapping (e.g. GPR, AI-assisted modelling) to improve route certainty
  
  

Solutions should reduce time on site, traffic disruption, reinstatement cost and delivery risk, while maintaining safety and quality.

TRL 4–7 solutions are encouraged, with a clear pathway to operational rollout.

What are the constraints?

Solutions must:
• Be safe to deploy around live gas assets and public highways
• Comply with street works, reinstatement and safety regulations
• Minimise traffic management requirements and road occupation time
• Integrate with existing asset records, GIS and delivery systems
• Be cost-effective and repeatable at scale
• Avoid increasing long-term maintenance or reinstatement risk

Who are the key players?

• Trenchless technology and guided bore specialists
  • Subsurface mapping and sensing providers
  • Construction technology and digital workflow companies
  • Utilities coordination and streetworks platforms
  • Universities and applied engineering research organisation

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

Challenge builds on:
• Existing trenchless and guided bore trials
• Early use of GPR and subsurface surveys
• Digital permitting and street works tools
• Collaborative street works initiatives across utilities:

What else do you need to know?

N/A

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Context  

Globally, the maritime sector is responsible for 3% of carbon emissions¹ and similarly in the UK, the shipping sector is responsible for one fifth of the UK’s total greenhouse gas emissions². As maritime and shipping are hard to decarbonise sectors, these percentage carbon emissions will increase as other areas decarbonise.  

There are several port functions where electrification is anticipated to be the best method of decarbonisation. These include ships running generators  when in port to provide energy for the ship and diesel ferries which conduct short frequent trips.  Such practices could be decarbonised through electrification, known as shore power, and enabled by the installation of onshore power supply (OPS) systems. As a result, by 2035, 2TWh may be required to supply shore power to UK ports³. In addition to  electrification of shore power and marine transport, ports are hubs for logistical and industrial development. Therefore, power demand at ports is expected to grow significantly between now and 2050.  

What is the problem?

Both decarbonisation via electrification, and industrial development at Marine ports is limited by high electricity network connection costs. These costs are often ‘lumpy’, with high initial costs difficult to justify due to potentially low demand in early years of deployment. The first comer in these situations may receive cash back via the Electricity Connection Charges Regulation (ECCR) second comer payments, but this is uncertain and doesn’t address high upfront costs falling to a single customer. Given the range of customers at some of these sites, a long-term solution could be to construct a 33kV cable.  In comparison, piecemeal investment at 11KV is sub-optimal for customers and the DNO – but this is the approach driven by customer-led connections investment. 

For example, a port may have an existing 11KV network connection of ~3MVA. This cable is at capacity and any new demand >1MVA would require a new additional 11kV cable running back to the nearest substation ~5km away – and would therefore cost ~£3M. There are several industrial customers at the site, with their total load increasing to 20MVA by the mid- 2030s with the most optimal solution therefore a new 33kV cable to the port (costing ~£8M). However, none of these customers would be able to risk fronting the £8M investment simply on the hope that others will connect and pay back via the ECCR.

What are we looking for?

We want to explore how innovative connection cost sharing arrangements could enable decarbonisation at ports and support the decarbonisation of shipping and maritime which are viewed as hard to decarbonise sectors. We also anticipate that these cost sharing arrangements would have other applications across different use cases. These include freeports and industrial and logistics hubs or clusters – all cases where there are a range of customers on site, all needing significant additional power to decarbonise and develop industrially. Often these sites have geographical limitations outside of the grid, for example, needing to be next to road and transport infrastructure, but where the electricity network nearby isn’t sufficiently developed for their needs. . Any solution identified could also address for example Motorway Service Area sites – where there may be multiple charge point operators looking for additional power, but no one can justify the initial cost.  

What are the constraints?

The regulations governing investment are clear. They relate to:

• Strategic network investment, focussed on reinforcing network based on anticipated demand, or
• Reactionary investment based on an accepted offer from a customer.

This leaves an investment gap, where no one is incentivised or able to fund the new connections which are essential for decarbonisation and net zero. There is a potential precedent set by the Green Recovery Fund, which built network, funded by bill payers, to “nodes” based on customer consultation, during ED1. 

Solutions may require us to go beyond our existing role to coordinate with stakeholders or seek the use of a regulatory sandbox to explore how regulated finance can be used in ways not currently allowed under existing network investment funding mechanisms. 

Who are the key players?

DNOs, port stakeholders, industrial clusters, free-ports 

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

Ofgem’s Access SCR made demand projects more viable by changing how the cost of reinforcement is distributed. The cost of reinforcement that is prompted by a new demand connection is now distributed via the Distribution Use of System Charges (DUoS). However, but the cost of sole use assets – the extension cable – is still chargeable to the connecting customer, and this varies significantly according to local circumstances, leaving a post code lottery for connecting customers. 

SSEN’s SeaChange project is building a ‘Navigating Energy Transitions’ (NET) tool, which will help ports to plot their most viable pathways for decarbonisation. This tool will also give network operators like SSEN visibility of the predicted electrical load arising from ports, which is estimated to be as high as 4,000 GWh per year’.

What else do you need to know?

N/A

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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.

Secondary substation transformers have remained largely unchanged for many decades, with advancement in material sciences is it possible to develop a secondary transformer that performs in a similar manner as existing models but is lighter and more compact while retaining the same performance and functionality as existing transformers.

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.

SSEN are looking for a new or unique transformer design which utilise modern materials which can operate under the same conditions as our current fleet of transformers. The proposed idea could be a prototype or a device in its trial stages. We would like to see suggestions which could reduce the overall weight, complexity or improve visibility through in-built communications.

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…)

Any new device would need to be able to perform as well as our current fleet of transformers. It would have to conform to all relevant standards for secondary transformers and operate in a similar fashion as the historic device.

All devices would need to be suitable for placement in either indoor enclosures or outdoor pads.

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?

Key stakeholders would theSSEN  Large Capital Delivery, Asset Maintenance and Operations teams

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 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?

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.

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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.

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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, 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: 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: 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

What is the problem?

Distribution Network Operators (DNOs) want to improve their ability to extend the life of overhead conductors, and improve network resilience. One area we have observed is a trend of conductor drops and overhead line (OHL) joint failures where tree contact is not the cause. Evidence suggests that components are reaching end-of-life due to age-related deterioration, loss of mechanical strength, corrosion, fretting fatigue, and legacy construction standards.

Current practice relies heavily on visual inspection and aged based modelling. However, none of these approaches allow a direct, field-based, non-intrusive measurement of the mechanical strength of in-service conductors or joints. Without this, we cannot reliably identify the specific spans, jumpers, or joints at highest risk of failure. This leads to unplanned outages, safety risk, and emergency repair costs.

The core question to innovators is therefore:

Can we directly measure (not infer via AI/ML) the mechanical health, tensile strength, structural integrity, and remaining life of legacy 11 kV and 33 kV overhead line conductors and joints using a short-duration, non-permanent, non-outage method?

What are we looking for?

We seek non-destructive, short-duration inspection or measurement technologies capable of quantifying mechanical strength or material degradation of OHL conductors and joints.

Solutions must be able to:

• Measure (not estimate) characteristics such as tensile stress, material fatigue, and conditions which increase the probability of failure.
• Operate live-line, avoiding outages.
• Be suitable for one-off or short-term deployment, not permanently installed hardware.
• Be deployable via drones, hot-stick techniques, hot-glove methods, or other contact-on, non-outage methods.
• Apply to legacy OHL assets, not new build designs.

Desired TRL

• Minimum TRL 3–5, with a credible route to field trial within the Basecamp programme.
• Technology may be adapted from other sectors (rail, aerospace, oil & gas, NDT industries).
• Should demonstrate laboratory validation or sector-agnostic proof-of-concept.

Possible solution directions (non-exhaustive)

• Portable NDT methods (e.g., magnetic flux leakage for ACSR, guided-wave ultrasonics, eddy current testing, acoustic emission).
• Drone-deployed NDT payloads able to clamp briefly onto a conductor.
• Temporary strain measurement devices assessing elasticity and creep.
• Localised microwave/THz interrogation of strand deterioration.
• New sensors for quantifying the condition of compression joints.
• One-off small form-factor devices lowered onto live jumpers to identify cracking or mechanical fatigue.

What are the constraints?

The solution must:

• Require no planned outage to install or deploy.
• Be suitable for live-line working or drone application.
• Be non-permanent (short-term fit or single measurement event).
• Comply with relevant DNO live-working rules, ENA TS/OHL standards, and ESQCR.
• Be applicable across multiple conductor types used in legacy UK OHL networks (e.g., SCA, AAAC, ACSR).
• Operate in typical UK environmental conditions (wind, temperature, salt exposure).
• Provide usable outputs that integrate into existing OHL asset health frameworks.
• Be cost-effective to allow sampling across large fleets rather than small, isolated trials.

Who are the key players?

DNOs

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

Relevant SNP projects (examples)

• OHL inspection & drone trials (UKPN, SPEN, NGED).
• PROACTIVE – Predictive OHL Asset Management (SSEN): analytical and modelling approaches but no direct measurement system.
• Dynamic Line Rating projects: measure temperature and sag, not mechanical integrity.
• Drone-based partial discharge detection trials (DNOs): electrical condition only.
• LiDAR and high-res visual surveys: good for geometry, not mechanical health.
• OHL risk modelling (SPEN & Northern Powergrid): algorithmic prioritisation, but lacking direct NDT input.

What else do you need to know?

• DNOs ideally want a technology that can be deployed span-by-span, sampling the asset population to inform targeted replacement.
• A successful innovation would enable a new asset-health dataset, which could later be paired with ML clustering or risk models (but only once direct measurements exist).
• Techniques proven in other industries (aerospace cable integrity, suspension bridge cable scanning, rail OHL tension assessment, oil & gas riser inspection) could be adapted.
• Proposed solutions should consider:
  • Safety and clearance constraints on live lines
  • Brief attachment mechanisms for drone payloads
  • Conductors under wind-induced oscillation
  • Short-duration tests
  • Compatibility with 11 kV and 33 kV assets, including jumpers and mid-span positions

Innovators should review existing ENA and network standards available on the Smarter Networks Portal, as well as previous OHL innovation projects, to ensure alignment and avoid duplication.

Download full document here

What is the problem?

Gas Distribution Networks operate large volumes of long-life, safety-critical equipment installed over many decades. A growing proportion of this asset base is now obsolete, unsupported by OEMs, or reliant on single-supplier or bespoke components.

Typical obsolescence issues across gas networks include regulators, slam-shut valves, pilots, actuators, filters, meters, heaters, E&I panels, telemetry units and kiosk components that are no longer manufactured or supported by OEMs.

Many of these assets rely on single-supplier spares, bespoke parts, or overseas refurbishment. As a result, otherwise serviceable assets are often repaired through limited spares or forced into premature replacement due to spares unavailability rather than asset condition.

What are we looking for?

Solutions may include (but are not limited to), which can be TRL 3–7, provided there is a credible pathway to network deployment.:

Digital & Data

• Network-wide obsolescence intelligence platforms.
• Digital part libraries with validated CAD models
• Cross-network spares visibility and interoperability
• New Asset Strategy & Decision Support that link asset condition, spares availability, risk and cost

Manufacturing & Repair

• Additive manufacturing (3D printing) for low-volume, safety-critical parts
• Rapid reverse-engineering of obsolete components that comply to standards
• Modular retrofit kits to extend asset life
• Certified local manufacturing approaches

Supply Chain Innovation

• New partnership models with SMEs, universities and manufacturers
• Distributed manufacturing for critical components
• Reduced reliance on single-supplier or overseas sources

What are the constraints?

Any solution must:

• Maintain or enhance network safety and regulatory compliance
• Be suitable for safety-critical gas assets
• Integrate with existing asset management systems
• Be economically viable at low production volumes
• Be deployable within GB regulatory and assurance frameworks
• Avoid creating new single-supplier dependencies
• Be customer focused with implementation in mind

Who are the key players?

Network operators, potential innovators from advanced manufacturing, digital twin and asset data platforms, universities and applied research centres, materials science and reverse engineering specialists.

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

Yes. This challenge builds on existing asset condition monitoring and obsolescence registers, Network Asset Management Strategies and Circular economy commitments within GD3.

Specific projects include https://smarter.energynetworks.org/projects/nia_sgn0153/

What else do you need to know?

N/A

Download full document here

What is the problem?

Gas pipelines at river and watercourse crossings are increasingly exposed to erosion, scour, flooding and channel migration, driven by climate change, extreme rainfall events and changing river dynamics. These assets are often buried beneath riverbeds or banks, where ground loss or exposure can develop rapidly and invisibly, particularly during storm events.

Inspection of river crossings is infrequent, reactive and heavily constrained by access, weather conditions, environmental permitting and safety risks. As a result, early indicators of movement, exposure or structural vulnerability are often missed, increasing the likelihood of unplanned outages, emergency works, environmental harm and safety incidents.

There is a growing need for earlier, data-driven visibility of river-related threats, enabling networks to intervene before assets become exposed or unstable.

What are we looking for?

We are seeking innovative solutions that allow gas networks to proactively detect, monitor and predict river-related threats to buried pipelines.

Solutions may include (but are not limited to):

• Remote or autonomous monitoring of riverbeds and banks
• Detection of scour, erosion, sediment movement or pipe exposure
• Integration of hydrological, rainfall and environmental data
• Predictive models to forecast risk during extreme weather events
• Decision-support tools to trigger inspections or protective works

Solutions should support a shift from periodic inspection to continuous or risk-based monitoring, improving resilience and response times.

TRL 4–7 solutions are encouraged, with a clear route to operational deployment.

What are the constraints?

Solutions must:

• Be safe to deploy around live gas assets and watercourses
• Operate reliably during extreme weather and flood conditions
• Minimise environmental disturbance and permitting burden
• Integrate with existing asset, GIS and risk management systems
• Be scalable across multiple river crossings and catchments
• Be cost-effective relative to traditional inspection and repair

Who are the key players?

Gas Distribution Networks: asset integrity and climate resilience teams, Emergency planning and response teams
Innovators: Environmental monitoring and hydrology specialists, Remote sensing and satellite analytics providers, drone, LiDAR and sonar inspection companies, academic institutions with river dynamics expertise

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

This challenge builds on:
• Existing river crossing inspection and maintenance programmes
• Climate resilience strategies across gas networks
• Innovations around surveillance on drones, LiDAR and satellite imagery
• Increased regulatory focus on flood and erosion risk

What else do you need to know?

n/a

Download full document here

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.

SSEN use a wide range of generators for both planned and unplanned shutdowns. These generators could be placed in any location, and this often means they are left in remote and isolated areas, which leave them vulnerable to theft or damage. When a generator is damaged, it means the whole set needs to be replaced and repairs need to be completed. This removes the set from the fleet and could result in delays to planned work or customers experiencing longer unplanned loses of supply.

There is a particular problem with the leads being stolen – a form of copper theft. We have experience numerous issues of this happening with safety implications and further loss of supply for customers. We are especially looking for a solution to this issue.

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 looking for solution which could help reduce, mitigate or eliminate the damage caused by theft or criminal damage to our generators when they are being utilized. This could be a project or a fast follow solutions utilised by other industrials for the protection of heavy plant like generators.

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…)

The solution would need to be portable enough to be stored and moved with the generators and light enough that it could be installed by the crews on site.

Any digital solution would need to comply to all our cyber security policies and be available to our control room and depot environments.

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?

Key stakeholders would be internal SSEN teams. These teams would likely be our Connections department and Network Integrity teams, both have the main roles of overseeing planned and unplanned work.

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 does not build on any specific work either on SNP or within SSEN.

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: 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

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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

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What is the problem?

Climate-related risks to electricity distribution networks are increasing in frequency and severity. UK networks are already experiencing more frequent extreme rainfall, flooding, heatwaves, freeze–thaw cycles, drought-driven ground movement, and high-wind events. These hazards affect a wide range of assets such as substations, poles, cables, switchgear, and ancillary equipment.

While DNOs have begun developing climate risk assessments and high-level adaptation roadmaps, a critical gap remains in understanding the real-world effectiveness and cost-benefit of specific adaptation actions. Examples include flood defences, vegetation strategies, pole reinforcement/replacement, substation hardening, improved drainage, heat-resilient transformers, or relocating vulnerable assets.

The problem is that, although many possible measures exist, networks lack robust, comparable evidence on which actions deliver the best resilience uplift under different climate scenarios. Without this, DNOs face difficulty:

• Prioritising adaptation investment
• Demonstrating value for money to Ofgem
• Understanding region-specific impacts
• Designing long-term, least-regret strategies
• Embedding climate resilience into ED3 and future planning horizons.

The overarching question to innovators is therefore:

How can we develop tools, data, or frameworks that reliably quantify both the cost and the effectiveness of different climate adaptation measures for electricity distribution networks under a range of future climate scenarios?

What are we looking for?

We seek innovative methods, tools, modelling approaches, data frameworks, or combined technical/analytical solutions that provide quantifiable evidence for climate adaptation decision-making.

We are especially looking for solutions that can:

• Evaluate how effective specific adaptation actions are under various UKCP climate scenarios (e.g., high emissions, low emissions, 2050s/2080s timelines).
• Assign credible cost estimates (capex/opex/maintenance) to these actions.
• Quantify confidence levels around adaptation outcomes (e.g., reduced outage probability, reduced asset degradation, avoided losses).
• Support whole-life cost analysis and allow comparison across different types of measures.
• Provide decision-support tools that enable DNOs to identify the most cost-effective and “least-regret” actions depending on hazard type and network region.
• Potentially cover multi-benefit solutions that deliver resilience plus:
  • Carbon reduction
  • Biodiversity enhancements
  • Social vulnerability reduction
  • Improved reliability metrics.

TRL expectations

• Solutions may be conceptual (TRL 2–4) provided they include a credible path to demonstration.
• Alternatively, existing tools from other sectors (insurance, water, government climate risk, catastrophe modelling) may be adapted to the electricity system.

Examples of possible solution categories (non-exhaustive)

• Climate-impact modelling frameworks that simulate adaptation effectiveness.
• Probabilistic cost-benefit analysis tools for climate hazard scenarios.
• Spatial tools combining asset data with hazard maps to score benefits of interventions.
• Multi-criteria decision analysis platforms for adaptation option appraisal.
• Solutions that merge engineering models with climate datasets to forecast asset performance.
• Approaches for quantifying avoided customer impacts or reductions in expected unserved energy.

What are the constraints?

The solution must:

• Be compatible with UK climate datasets, especially UKCP18/UKCP23.
• Align with Ofgem’s developing climate resilience framework, including requirements from the Climate Resilience Stress Testing Exercise.
• Integrate with (or complement) DNO asset data structures, geospatial formats, hazard mapping, and risk scoring approaches.
• Be technology-agnostic or readily applicable across the four GB DNOs.
• Be capable of being rolled out or trialled within the Basecamp project timeframe.
• Produce outputs that are auditable and suitable for regulatory reporting.
• Where data is uncertain, present transparent assumptions and ranges rather than black-box outputs.
• Comply with security and data-sharing requirements (asset locations, flood maps, etc.).
• Recognise that budgets are constrained and must demonstrate scalability / replicability.

Who are the key players?

Primary stakeholders

• All GB DNOs (asset management, network strategy, resilience, investment planning teams).
• Ofgem – especially through the Climate Resilience Stress Testing work and future ED3 planning.
• ENA Climate Change Resilience Working Group (CCRWG).
• Infrastructure UK, National Infrastructure Commission (NIC).

Secondary stakeholders / contributors

• Modelling organisations (e.g., Met Office, climate impact consultancies).
• Universities with expertise in climate impact modelling, geospatial analytics, and resilience engineering.
• Insurance and catastrophe modelling organisations.
• Local authorities and regional flood resilience partnerships.
• Emergency planning and civil contingencies groups.

End beneficiaries

• Customers in high-risk regions (flood-prone, coastal, exposed rural networks).
• Vulnerable communities with a higher sensitivity to climate-related power disruption.
• Network operators through reduced outage costs and avoided asset failure.

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

Yes. This problem statement expands on several strategic initiatives already underway

Existing work / foundations:

• Climate Change Resilience Working Group (CCRWG) work on building sector-wide resilience methodologies.
• Ofgem’s Climate Resilience Stress Testing Exercise, which identified major gaps around quantifying adaptation effectiveness and costs.
• DNO climate risk mapping projects on the Smarter Networks Portal (e.g., flood resilience studies, heat mapping, environmental hazard models).
• Various regional adaptation plans and risk assessments developed during RIIO-ED2.
• Government frameworks such as CCRA3, NAP3, and the National Infrastructure Commission’s work on resilience standards.

What else do you need to know?

• Adaptation decisions are inherently uncertain; innovators must consider scenario-based approaches, not single forecasts.
• Outputs must be practical and operationally meaningful — e.g., turning complex model outputs into clear, prioritised investment recommendations.
• Networks will expect tools that can handle multiple hazards, including:
  • Pluvial & fluvial flooding
  • Coastal inundation
  • Heat impacts on network assets
  • High winds and storms
  • Lightning
  • Ground movement due to drought

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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.

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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

What is the problem?

Gas networks operate a large number of critical operational sites including regulator kiosks, telemetry stations, compressors and control assets that rely on grid electricity for safe and reliable operation. Many of these sites are remote or exposed, where grid connections are costly, unreliable, or vulnerable to outages caused by extreme weather and wider system failures.

Current backup solutions such as diesel generators and limited solar installations are carbon-intensive, costly to maintain, and operationally inefficient. Grid outages directly impact telemetry, SCADA visibility, pressure control and safety systems, increasing operational risk during precisely the conditions when resilience is most needed.

In parallel, large industrial and commercial customers are facing growing pressure to decarbonise while maintaining secure, high-load power supplies. There is a gap between electricity network capacity, resilience requirements and the availability of low-carbon on-site generation options at scale.

There is a clear opportunity to demonstrate gas-to-power solutions, including fuel cells, to provide reliable, low-carbon power both for network-owned assets and for large industrial loads.

What are we looking for?

We are seeking innovative gas-to-power solutions that can provide secure, resilient and low-carbon electricity for:

1. SGN-owned operational sites (e.g. kiosks, telemetry stations, SIUs)
2. Large industrial and commercial loads requiring reliable, continuous power

Solutions may include (but are not limited to):

• Fuel cells using natural gas, biomethane or blended hydrogen
• Hybrid systems combining fuel cells, batteries and intelligent load management
• Modular gas-to-power units for remote or constrained locations
• Waste heat recovery to improve system efficiency
• Smart control systems integrating telemetry and demand response

Solutions should demonstrate how gas infrastructure can support both operational resilience and decarbonisation, rather than acting solely as backup.

TRL 4–7 solutions are encouraged, with a clear pathway to deployment and scaling.

What are the constraints?

Solutions must:

• Be safe and compliant for operation near live gas assets
• Operate reliably in remote and harsh environments
• Integrate with existing SCADA, telemetry and control systems
• Reduce whole-life carbon and operational costs versus diesel
• Be scalable across multiple sites and load profiles
• Support future transition to biomethane and hydrogen where feasible

Who are the key players?

Gas Distribution Networks: E&I and control team, Industrial and commercial energy users

Potential Innovators: Fuel cell technology providers, Gas-to-power system integrators, Energy storage and hybrid system developers, Industrial decarbonisation specialists, Universities and applied research organisations

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

This challenge builds on: innovations exploring gas-powered generators and fuel cells.

What else do you need to know?

N/A

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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.

The core problem is that the Distribution Network Operator (DNO) sector faces a strategic workforce challenge: customer demand for services is projected to outstrip the sector’s ability to resource that demand using current ways of working. This means that, without significant innovation in recruitment and skills development approaches, the sector will struggle to deliver on its commitments, especially those related to decarbonisation ambitions. Key aspects of this problem include:

• Ageing workforce and limited capacity for effective knowledge transfer.
• Shrinking talent pipeline, worsened by reduced international mobility and ineffective relocation strategies. The sector is competing heavily with other large infrastructure markets for skills.
• Evolving job roles driven by AI, robotics, and data analytics, which are not yet reflected in current training or career frameworks.
• Safety risks in traditional field roles that could be mitigated through automation and immersive training technologies.
• Disconnect between modern learner expectations and traditional analogue work environments.
• Need for massive network upgrades to meet 2050 decarbonisation goals, requiring a skilled and adaptable workforce. Traditional hiring and apprenticeship models are not sufficient to meet future demand, partly because it takes up to four years for apprentices in craft roles to qualify and work independently. This creates a bottleneck in workforce capacity.

Wider Context of the Problem

This workforce challenge is set against a backdrop of rapid technological change and ambitious national goals:

• The sector is undergoing a whole-system transformation and technology will need to be used to reshape workforce models.
• There is an urgent need to accelerate the delivery of network interventions through AI and robotics.
• Critical engineering roles (e.g., Control Engineer, System Planning Engineer, HVDC Engineer) will evolve, requiring new career architectures.
• Safety and efficiency improvements are a priority, with automation and robotics expected to reduce risks and make the sector more attractive to new talent.
• The sector is keen to address social mobility, targeting talent in deprived communities and aligning with evolving apprenticeship models and government funding.

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.

What kind of solution is wanted?

The challenge proposes an industry wide transformation of the Distribution Network Operator (DNO) workforce model. The focus is on leveraging AI, robotics, and immersive technologies to address workforce challenges, including recruitment, training, safety, and capacity. The aim is not just to evolve existing roles but to reshape the entire workforce structure to meet future needs, especially in the context of decarbonisation ambitions

Key solution areas include:

• Impact of technology on critical jobs (e.g., Control Engineer, System Planning Engineer, HVDC Engineer)
• Accelerating delivery of network interventions through AI and robotics
• Improving safety and training (automation, VR, AI agents)
• Promoting social mobility (targeting talent in deprived communities)
• Delivering tangible business value (cost avoidance, improved performance).

What TRL are you looking for?

We do not have an exact Technology Readiness Level (TRL). However, part of the challenge includes the need for AI-driven capacity release and the use of technologies such as GenAI, robotics, and immersive VR. There is an expectation that solutions should be robust enough to accelerate the delivery of fully trained, competent staff, and that traditional hiring alone is insufficient.

However the main crux of the challenge is the people and culture side; how do we ensure that we have the right workforce, in the right roles, with the right supporting technology to ensure that DNOs facilitate GB’s economic and decarbonisation goals – and are not the blocker?

Does the solution need to be operable at scale?

Yes, a key part of the challenge is the need for solutions that can unlock capacity at scale. The emphasis is on scalable interventions that can address industry-wide challenges, not just isolated pilots.

Are you looking specifically for methods and techniques?

This challenge is open to a range of solutions, including methods, techniques, and technologies. We have no set solution in mind, however initiatives could include:

• Safe working on all jobs
• AI technical report agents
• PowerFactory optimisation agents
• Dynamic dashboards & emergency response
• Introduction of robotics for high-volume tasks

Does the idea need to have been tested to a certain extent already?

The challenge does not require that all ideas be fully proven, however there is a clear preference for solutions that are robust and have a fresh perspective.

What are the constraints?

There are no constraints. We appreciate it is a wide, far-reaching challenge, so are open to it being split up into more manageable chunks, but keeping the big picture in mind. One suggestion of breaking down the challenge is:

1. Technological transformation of job roles: Key engineering roles will evolve due to AI and robotics, requiring new career frameworks that anticipate future job architectures. This is a rare chance to not just alter existing job roles but look at whole system transformation of DNO job roles to meet the needs of the evolving low carbon network.
2. Enhance safety and training: Automation reduces risks in dangerous tasks; immersive VR and AI enable remote, tech-native training; how can robotics reduce risk.
3. How do we recruit the volume of talent that we need to meet our decarbonisationtargets; Can we use targeted recruitment that supports social mobility aligned with apprenticeship models and funding, helping to create jobs in our local communities. Do we start this talent pipeline now with school age children? How do we align this with forecast network development requirements and workload?

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?

Key Stakeholders

Distribution Network Operator (DNO) leadership and workforce — the challenge centres on a industry wide transformation of the DNO workforce model, so executives, functional leaders, planners, control room teams, craft/field staff, and enabling functions are all directly impacted.

Future Apprentices and trainees — long time‑to‑competence (≈4 years) and constraints on lone working put limitations on training capacity.

H&S (Health & Safety) stakeholders — safety risks in traditional field roles and the push to automate dangerous tasks make safety teams central.

Recruitment, Learning & Development, and workforce planning — the shrinking talent pipeline, evolving job roles, and modern learner expectations require new, attractive, training methods, and career frameworks.

Regulatory and performance stakeholders — benefits are framed against price control commitments and business delivery outcomes.

Target Market

We have no specific targeted innovators or market.

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?

Where the challenge targets the workforce, there is interplay with a huge range of projects.

There are no specific enablers that innovators should reference or specifically build on in their proposals and there are no solutions which have already been considered / trialled.

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