Scotland's electricity and gas networks: vision to 2030

Based on Scotland's energy strategy, this document looks at the ways in which Scotland's electricity and gas network infrastructure will continue to support the energy transition.

Chapter 2: Developing the network Infrastructure

Electricity Networks

Our Vision: by 2030… there will have been the necessary substantial investment in new capacity for our electricity networks, including transmission links to our island groups and new undersea cables linking to the rest of Britain between Scotland, England and Wales. There will be a strategic focus on security of supply and resilience when designing these networks and the systems that they connect to. New distribution network investment will be balanced against the use of smart grid systems which have created opportunities for flexibility and thriving local markets for both the generation and use of electricity and flexibility.

Gas Networks

Our Vision: by 2030… gas networks remain a vital and flexible component of Scotland's national infrastructure, delivering affordable energy for heating our homes and businesses. The energy resource carried by the networks will be lower carbon than it is today. The policy, regulatory and technical developments will have been put in place to allow natural and low carbon gas to be blended in the networks, including a contribution from hydrogen. We will also understand clearly the feasibility and costs of repurposing the gas networks to carry 100% hydrogen, and will have made strategic decisions about the long term role of the networks and the wider decarbonisation of heat.

We expect the electricity and gas network companies to rise to the challenges of decarbonisation during the coming decade - focusing on how they can deliver low carbon energy to consumers, whilst helping us maintain affordable and secure supplies. Reliable and low carbon energy is an essential service, which gas and electricity networks have an obvious and central role in delivering. This essential service needs to be at the heart of how we plan those networks. We need to ensure that all parts of Scotland, from our major cities to our remote island groups, are connected in the best and most efficient way.

By 2030 electricity networks will be smarter, flexible and more efficient, while our gas network will have evolved to deliver lower carbon gas through the existing pipes - based on a new and detailed understanding of its role in decarbonising the energy system.

Investment decisions must take full account of Scottish Government and local authority policies and priorities. This will encompass our Energy Efficient Scotland Route Map and goals, as well as our policies to promote ULEV growth. Our local authorities will need the support and cooperation of the network companies as they develop their LHEES, with those companies using their knowledge of these strategies to adapt and improve their own investment plans and decisions.

Electricity and gas networks will continue to transport energy round the country safely, and with extremely high levels of reliability - for instance, we expect to see electricity and gas transmission networks maintain or improve today's reliabilities of more than 99.99%.

This will be a substantial challenge. The high levels of reliability we see today derive from decades of experience of working with systems based on supplying gas and electricity from large, centralised power stations and gas terminals. Our networks have also developed appropriate levels of redundancy and back up, based on their knowledge and experience of how often faults happen, and what is needed to ensure that those faults do not affect consumers.

The changes expected over the coming decade and beyond will fundamentally alter how these networks will operate - challenging and reversing many of the existing assumptions used in their design and operation. This means we will have to work hard at understanding how to ensure that the new systems remain at least as reliable as the old ones.

Scotland's energy networks are already beginning to incorporate new and innovative market platforms for matching local supply and demand, as well as pioneering active network management approaches, and the introduction of decentralised, low carbon gas producers. We expect this progress to continue, and our network companies to play a huge part in bringing consumers with them on this journey.

We want to see markets and approaches develop in ways which inform, encourage and reward those consumers who can adapt their energy use and behaviour in ways that make the best use of our networks. This will include incentives for matching local supply and demand - tackling network constraints, providing business models and creating opportunities for local and community energy projects.

We appreciate that there are still uncertainties in play. For example, many of the decarbonising technologies and approaches which we are likely to rely upon aren't yet technically or commercially mature.

Our Energy Strategy included two illustrative pathways for the energy system in 2050, consistent with our current climate change targets: hydrogen, and electrification. These are designed to help us understand the different infrastructure and behaviours that might be needed, depending on progress and decisions over the coming years.

The electrification pathway features technologies that are close to mature today, such as heat pumps and electric vehicles. However, it would depend on continuing and significant investment in new electricity infrastructure to replace gas supplies as demand for heat shifts to electricity; and, whilst the technologies themselves are mature, appropriately coordinating them remains a major challenge which is likely to require significant innovation.

By contrast, the hydrogen pathway comprises technologies that are yet to be proven on a large scale, such as Carbon Capture and Storage (CCS), and the development of large scale hydrogen gas networks. However, this pathway would retain the greater flexibility that gas networks provide - compared to electricity.

The most likely outcome may well be a mixture of these pathways - for example, greater electrification in some areas, and a hydrogen and low carbon gas future in others. New and disruptive technologies and innovations could also emerge, providing alternative and faster routes to a decarbonised future. We need to assess and understand the various available options between now and 2030, and to decide and prepare for the major changes and investment which will be needed.

These are technical challenges, with often technical solutions. We need to understand how they might affect our access to energy and our relationship with networks. Table 1 summarises the key technical challenges that we will face, and the rest of this section explores these issues in more detail.


Transmission network

Our electricity system is changing radically. Scotland's last coal power stations at Cockenzie and Longannet have closed in recent years, while renewable generating capacity exceeded 10 GW in 2018 - leading to a huge reduction in the carbon intensity of our electricity supply. The shift to renewables means that supplies within Scotland have become more variable, increasing the importance of the transmission network linking us with England and Wales.

Two major projects are in the process of increasing the capacity of the Scottish transmission network. The Western HVDC[5] Link, which connects Hunterston to Deeside in North Wales via an undersea cable, will add around 2,200 MW of new capacity to the transmission network - allowing more electricity generation in Scotland to connect and meet demand across Britain.

The Caithness-Moray HVDC link is a 1,200 MW undersea connection between Spittal in northern Caithness and Blackhillock in Morayshire, which was commissioned in January 2019. This link increases the capacity available to transport renewable electricity generated in northern Scotland, including Orkney and Shetland, into the wider transmission network.

But we will need more investment in new transmission infrastructure to connect the levels of renewable generation we want by 2030. We expect this to include new links between Scotland and England, as well as within Scotland - including those needed to connect the huge marine renewables potential around our coasts, and wind generation on the Western Isles, Shetland and Orkney. This will require regulatory and investment decision processes capable of identifying, agreeing and delivering these in a timely way.

Some proposals are in the early stages of development, including two additional undersea cables on the east coast linking Scotland with northern England. These links need to be designed to support the networks' resilience, as well as allowing energy to flow where it needs to.

Recommendations to take forward these projects, as well as others that reinforce the main integrated part of the transmission system in Britain, are taken by National Grid Electricity System Operator through the annual Network Options Assessment (NOA) processed. This identifies the benefits of each upgrade across four Future Energy Scenarios[6]. National Grid works closely with the Transmission Owners to identify the costs and benefits of a range of options for upgrading the network.

The NOA process in 2018 recommended investment in electricity transmission networks in Scotland of between £0.94 Billion - £1.45 Billion[7] across 6 to 10 projects over the range of the Future Energy Scenarios. In 2019 the NOA assessment specifically identified the need for two reinforcements of at least 2 GW each.

Proposals for transmission links to each of the island groups have now been submitted under Ofgem's Strategic Wider Works process. Delivering these requires Ofgem to approve a 'needs case' from the Transmission Owner which lays out the costs and benefits that the link will bring, both to the islands and across the British system. We believe that these links, and the huge renewable energy potential that they can help connect, will benefit the local economies of the islands, as well as further decarbonising electricity supplies for everyone in Britain.

We will also need strong interconnections to our European neighbours - ensuring that Scottish renewable generation has access to as wide a market as possible and helping to meet demand and supporting network operation when required. We welcome the proposals to link Norway to Scotland via Peterhead and Shetland, and remain open to the possibility of further links to the all-Ireland electricity system and other European neighbours.

Box 3: The changing electricity transmission network

The way that electrical energy flows over the transmission network has changed significantly over the past decade, with increases in the quantity of energy flowing both in and out of Scotland. In 2017, we exported nearly 50% more energy to England and Wales than in 2010, with upgrades of the transmission network increasing the peak-flow that the transmission network can accommodate from around 3 GW to 4.4 GW. The Western Link is expected to increase this to 5.7 GW in the near future.

We also import more electricity from England and Wales following the closure of Scotland's coal stations. We imported to Scotland for 12% of the time in 2017 compared with 8% in 2010. Currently the ability of the network to securely import electricity into Scotland is estimated at 2.65 GW and is expected to rise to 3.9 GW on completion of the Western Link.

Figure 1: sharing power - the flow of electricity between Scotland and England in 2010 and 2017

Figure 1: sharing power - the flow of electricity between Scotland and England in 2010 and 2017

The capacity of the electricity transmission network to move power around the country represents one dimension of its role in delivering a secure electricity system. There is a wide range of other factors which need to be considered. The design and operation of the transmission system has a major bearing on the ability of the electricity system as a whole to respond to faults, to maintain safe voltages, to be resilient to storms, and to recover quickly from a major black-out. The changing nature of the electricity system in Scotland means that these operability and resilience issues must be at the heart of discussions about upgrading the network.

Figure 2: New transmission links will be needed to ensure that Scotland is able to make the most of opportunities for renewable generation and to ensure security and reliability of electricity supply in Scotland. This will include new links with our Island Groups, with E&W and with our European Neighbours.

Figure 2: New transmission links will be needed to ensure that Scotland is able to make the most of opportunities for renewable generation and to ensure security and reliability of electricity supply in Scotland. This will include new links with our Island Groups, with E&W and with our European Neighbours.

Operating and securing the system

Network design and operation is about more than just capacity; networks also have an important role in linking the wider electricity system. The difference between wind turbines and fossil fuel power stations is much deeper than just the fuel used. New sources of energy are connected using very different technical principles. This means we will need to redesign many of the systems we've traditionally relied upon to ensure the safety, security and reliability. Box 4 provides more detail.

National Grid ESO, the GB electricity transmission system operator, will continue to need ancillary services to operate and ensure stability and resilience across the system as well as back up generation - response and reserve services. This will mean continuing the current trend and efforts to open up these markets and to source the relevant services from new and increasingly small-scale parties. These mechanisms need to be designed to take account of the physics, the engineering and the economics of the new providers.

Conventional transmission connected generators will also continue to have a role. For example, new pumped storage hydro capacity can provide valuable network services. However, the large capital investment involved in these projects mean that developers need to have confidence that there will be sufficient revenues available for the ancillary and system services they provide over years or decades. The way these services are procured needs to consider the long term investments required to bring forward new pumped storage projects.

Box 4: Keeping the electricity system operating

There are several ways in which new sources of electricity such as wind farms, solar panels and HVDC interconnectors differ from the large fossil fuel power stations which are coming offline. Each of these differences has implications for how we design and operate the electricity networks and the whole electricity system.

New generators are often smaller; this means that a larger number needs to be coordinated to deliver the same level of services that used to be provided by one or two large generators. The majority of these smaller generators are distribution connected, meaning that we need to change the way we plan and operate the distribution networks as well as reviewing the interface between distribution and transmission. This is important to to ensure that we can use those generators, as well as other resources connected to the distribution network, to support the wider system.

Renewable generators are intermittent. This means that we need to find ways to make sure that the system can still operate, and meet demand, when the wind doesn't blow or the sun doesn't shine. Their output is also uncertain, meaning that we need back up that is flexible and able to respond quickly to changing conditions.

Finally, wind and solar generation, like HVDC interconnectors, are not synchronised to the system frequency. This creates new challenges for operating the system in a stable way.

As well as delivering energy, power stations have traditionally provided a range of services to keep the system balanced and the networks operating. We need to plan carefully to ensure that the resources connected to our networks can do the following:

  • Manage network voltage: keeping voltage within statutory ranges ensures that the system is safe, and that equipment connected to the network is not damaged. Renewable generators, such as wind farms, have the capability to support voltage, even when it isn't windy; we need to make effective use of this capability, as well as other options such as new network equipment and greater use of distributed connected generators, consumers and storage.
  • Keep the frequency stable: large fossil and nuclear generators are synchronised into the frequency of the system. They provide 'inertia' which helps keep the system balanced in the first few seconds after a major fault. Networks have always played an important role in linking sources of inertia across the country. Wind turbines, solar panels and HVDC interconnectors are not synchronised and we need to find new ways of either replacing the lost inertia, or keeping the system stable through new techniques. New sources of backup power, such as battery storage, can respond to changes in frequency within a second or less, and there is potential to develop ways to use wind, solar and interconnectors to rebalance the system quickly after a fault.
  • Detect network faults: fewer large synchronised generators and greater quantities of generation connected to the distribution network mean that the response to 'short circuits' and other network faults is different. In some cases, 'fault level' limits mean that new distributed generators cannot be connected without new investment. Keeping the system safe will remain the number one priority for network companies and the ESO. However, doing so in a cost-effective way may mean thinking again about the design of some of these systems.
  • Resilience and black start: we have never suffered a full-scale black out across the whole British electricity system, and there have been relatively few major power interruptions in recent decades. However, if a black out should happen, we must be able to restart and repower the system quickly and safely. Large thermal power stations spread across the British electricity system have traditionally been at the heart of plans to 'black start' the system. When new large power stations are developed, decisions over where they are located should take account of the locational benefit they can provide - for example, their ability to support faster restoration following a black out. We will also have to do things differently in the future; this means that we must develop ways to use distributed generators, renewables and interconnectors. Ofgem's announcement in 2018 of £10.3 million for National Grid and SP Energy Networks to investigate the use of distributed generation to support a black start is a positive step.

Some of the services that National Grid use need to be provided at the right location on the network. For example, managing the voltage on the transmission network in Scotland depends on appropriate voltage support from providers within Scotland. But getting power stations to locate in Scotland is difficult due to the current combination of location specific network charges, but limited location specific revenue streams. We think that the locational value that new power stations, demand-response projects battery storage projects and others can provide across a range of services, needs to be taken much more into account.

We believe that the planned review of the Capacity Market mechanism must consider the locational value of capacity. This would help ensure that we have the right quantities and kinds of capacity in the right places across Scotland and Great Britain - making our networks and systems more reliable, resilient and secure.

Distribution networks

Electricity distribution network planning and operation will also be very different in 2030. We are in the early stages of a shift from Distribution Network Operators (DNOs) to Distribution System Operators - the 'DSO transition' (see Box 5). This will mean that distribution network customers - including household consumers, micro-generators, storage providers - will be able to use their flexibility to generate income. Data from smart meters, and the ability for 'real-time monitoring' of the distribution network itself, will be used to keep the network safe and secure.

Box 5: The DSO transition

A process is already underway which will fundamentally change the way in which electricity distribution networks are planned and operated. Constraints on these networks - areas where there isn't enough available capacity - mean that new customers (consumers, generators and increasingly energy storage providers) often can't connect without paying large costs for new capacity that may end up rarely being used. One solution is the development of Distribution System Operators (DSO) allowing substantially more flexibility over how distribution networks, and the systems they connect, are planned and operated.

DSOs will take a much more active role than DNOs do at present; they will have much greater awareness and visibility of the small generators and demand customers across these networks, and be able to enter into contracts for particular supply and demand services.

DSOs will be able to match local supply and demand, enabling much more flexible behaviour across the distribution network. This will allow the networks to connect new customers, identify when demand and generation could risk overloading the network, and take steps to influence behaviour.

This could lead to new and local markets in flexibility - where consumers can offer to reduce their demand, or generators and energy storage operators increase or reduce their generation, to keep the network safe. This already happens on a national scale. Innovative aggregator companies such as Edinburgh based Flexitricity are leading development in this field, helping businesses to get value from providing flexibility to the System Operator. In future, aggregators will also play an important part in delivering flexibility to support the local networks.

The Scottish Government believes that the following principles should guide the design of the DSO role over the coming years:

  • Safety: This must remain the number one priority, with clear and well defined responsibility for maintaining safety.
  • Security: Greater flexibility shouldn't come at the expense of security of supply; as above, there should be a single party responsible and accountable for dispatching the system, and making sure that demand is met at all times.
  • Efficiency: The DSO transition should help make our distribution networks more efficient in future. The networks will need structures which can adjust to changing circumstances, and provide different solutions in different areas.
  • Openness: Everyone should be able to provide services to DSOs, using transparent and fair processes. Those who aren't familiar with providing network services, such as community groups and local authorities, should have access to the help and advice that will allow them to do so.
  • Risk sharing: Today's world involves taking long term investment decisions in the context of a fast changing energy system. The DSO transition allows us to review our understanding of risks, and who should carry them - creating the flexibility to keep options open when possible and appropriate, but with timely investment decisions still being taken when needed.
  • Adaptable: Technological disruptions and advancements are creating new opportunities and challenges. The development of DSOs over the coming decade will need to happen in a way which enables systems to anticipate and react to emerging solutions, innovations and evidence in areas including the best ways to decarbonise heat, and how to respond to changing and growing demand from electric vehicles.


The gas networks will be an important part of the energy system in Scotland in 2030 and beyond, continuing to bring energy to the majority of the properties in Scotland. Gas currently provides low cost, reliable energy for heat, and represents the cheapest large-scale way to provide heat for the majority of homes, businesses and industrial processes. It is also a source of valuable flexibility across Scotland's energy system - an aspect that energy policy and system planning needs to keep clearly in mind.

Our vision for the gas networks requires the following:

  • identifying and recognising the value that the gas network provides to the broader energy system, including the flexibility it provides;
  • partial and increasing decarbonisation of the gas in the network between now and the end of the 2020s through the introduction of low carbon gases such as biomethane and hydrogen; and
  • developing the evidence about the technical feasibility and cost effectiveness of converting the gas networks to supply 100% hydrogen.

The gas networks today

Gas remains the largest provider of heat in Scotland - connecting around 83% of domestic customers in 2016, delivering around 33% of total energy including 66% of all domestic energy. Gas also acts as a fuel and feedstock for industry, with some of the largest users of gas in the UK located in Scotland, contributing to a robust economy with opportunities to include a wider global market.

Current data[8] shows that domestic consumers pay around 3.6 pence per kWh for gas in Scotland; this compares with 14 to 16 pence per kWh for electricity on a standard tariff, with off peak electricity available at between 8 and 10 pence per kWh.

Figure 3: Gas injected into the National Transmission Network (NTS) at St. Fergus meets a substantial fraction of total British demand for gas. This graph shows the total energy injected at St. Fergus each day in 2017 and where that energy was used.

Figure 3: Gas injected into the National Transmission Network (NTS) at St. Fergus meets a substantial fraction of total British demand for gas. This graph shows the total energy injected at St. Fergus each day in 2017 and where that energy was used.

Figure 4: Gas pipes across Britain act as a substantial energy store, known as linepack, and this is used every day to provide flexibly. This graph shows the NTS linepack capacity used each day to help balance supply and demand.

Figure 4: Gas pipes across Britain act as a substantial energy store, known as linepack, and this is used every day to provide flexibly. This graph shows the NTS linepack capacity used each day to help balance supply and demand.

Figure 5: Energy storage is important across the energy system. Pumped Storage is central to the operability of the electricity networks but is relatively small in capacity terms; linepack helps us meet within day variations in energy demand, and dedicated gas storage sites provide bulk storage capacity which can be used to provide monthly or seasonal flexibly.

Figure 5: Energy storage is important across the energy system. Pumped Storage is central to the operability of the electricity networks but is relatively small in capacity terms; linepack helps us meet within day variations in energy demand, and dedicated gas storage sites provide bulk storage capacity which can be used to provide monthly or seasonal flexibly.

Gas containing 329 TWh of energy, with an estimated wholesale market value of £5 billion, was injected into the National Transmission network at St. Fergus during 2017. Around 18% of this was used to meet Scottish demand, with the rest exported (11% to Ireland and 71% to England). Around 40% of GB-wide demand for gas in 2017 came via St. Fergus and through Scotland.

Over and above the energy that it supplies, the gas network also provides us with important flexibility and energy storage. The gas network stores energy within its pipes and provides important daily flexibility through 'linepack'. Supplies of gas are pumped into the network overnight, increasing the pressure, and this energy is stored until demand picks up during the early morning. As more gas is drawn out over the course of the day, the pressure falls. Linepack means that the GB gas network provides flexibility through daily storage, exceeding 300 GWh during some days in winter.

In addition to the energy stored within the network itself, there are 14,000 GWh of distinct energy storage facilities connected to the GB gas network.

The gas network is therefore able to provide daily and inter-seasonal energy storage well beyond the capability of the electricity system. Pumped Storage Hydro plays a critical role in supporting the operation of the electricity network, providing important ancillary services and reserves. However, its role is quite different to that which the gas network's bulk storage can provide.

Although the gas network delivers low cost and flexible energy, the energy that it delivers today comes from a fossil fuel. Burning natural gas releases 182 g CO2 per kWh, compared with just 54 g CO2 per kWh for electricity generated in Scotland in 2016. We need urgently to decarbonise the gas that flows through the gas network, and to explore whether it will be feasible and cost effective to re-use the gas network in future to deliver fully decarbonised energy.

The gas networks during the 2020s

The UK Committee on Climate Change recommended in 2016 that work begin now on decarbonising heat, in order to deliver change over the coming decade[9]. The Scottish Government's Climate Change Plan, published in February 2018, acknowledges this need, and sets out ambitious and challenging trajectories for decarbonising our heat supply. The Plan recognises that decisions on future decarbonisation of the gas network are a reserved matter.

The UK Government needs to fulfil its commitment to take a decision on the approach to decarbonising heat as early as possible in the next Parliament. This will give network operators, investors and governments sufficient time to plan for any transition of the gas network, and to understand the implications for levels of demand.

We have committed to review our approach to low carbon heat - and in particular support through the Energy Efficient Scotland programme - in a future Climate Change Plan, once this aspect of UK Government policy has been clarified.

We know that the gas network can deliver flexible energy at an affordable cost; our aim should be to decarbonise that energy as far as possible between now and the end of the next decade, without sacrificing those qualities.

There is significant potential to produce and blend low carbon gases with supplies of existing natural gas, partially decarbonising the gas that is delivered to consumers. Opportunities include the use of biomethane and low carbon hydrogen. The networks themselves, and the regulations which govern them, need to be in a position to deliver this. More specifically, we need to update our Gas Quality Standards, and the way in which customers are billed for the gas that comes through the networks.

Current Gas Quality Standards were designed around natural gas from the North Sea, which didn't envisage the need to inject transport hydrogen or low carbon gases into the network. Limits on the makeup of the gas that can flow through the network are set out in the Gas Safety (Management) Regulations (GS(M)R) 1996. For example, the existing standards limit the percentage of hydrogen allowed in the gas network to 0.1% by volume, well below what is allowed in other European countries.

There is growing evidence that these standards can be widened, and low carbon gas transported through the distribution and transmission networks - significantly reducing the carbon intensity of gas over the next decade, without compromising safety.

Work is progressing at a UK level through the Institution of Gas Engineers and Managers, and at EU level through work to ensure an integrated market for suppliers across the EU. We welcome this focus, and expect to see more examples of networks working together with equipment manufacturers to verify the safety of new gas mixes and how they can work with new and existing equipment.

We also need to update the legislation that sets out the methodology for the way customers are billed for the energy that they receive. The energy content of natural gas is calculated using nationally averaged values over large geographical areas or zones. This does not allow for the variations in the energy content that we will see as locally produced low carbon gas becomes more prevalent. Low carbon gas, including blends of natural gas and hydrogen, tends to have lower energy content, and this needs to be reflected in the energy that consumers use and are charged for.

With focused work in this area, we may be able to see hydrogen blended into the network at penetrations of between 2% and 20% by volume, and fossil fuel gas mixed with low carbon gas like biomethane. This has the potential to provide a substantial carbon saving through the 2020s.

The gas network companies across Britain have recently launched a project to develop a full pathway for decarbonisation of the gas network. This will provide the next step in a coordinated approach to understanding the opportunities and barriers across both transmission and distribution, and how these vary across the country.

As well as pushing incremental decarbonisation, companies will continue to invest in the network, both to maintain the service it provides and to connect new customers. Network companies are currently considering business plans for the next price control period (2021-2026). The case for investment, reinforcement and potential expansion of network infrastructure will be influenced by several factors. These will include an assessment of the potential for access to gas to affect fuel poverty, as well as a comparison with alternative options for providing low carbon heat.

Investment decisions for general network development are made by the gas network company, operating within a framework created by Ofgem, while specific extensions or 'infill' projects are a matter for the gas network company and new connecting customers. There are currently 36 live infill projects underway in Scotland which have the potential to connect 4,719 new properties to the gas mains, with around 1,700 supported by the Fuel Poor Network Extension Scheme.

Investment decisions will also need to consider broader policy developments for decarbonising heat in Scotland. The Scottish Government is committed to exploring and supporting a range of options to decarbonise heat during the short term - with a focus on measures which will prove to be effective and good value for money, no matter which pathway to full decarbonisation emerges as the best.

Regardless of the technologies, fuels, or pathways which emerge, increasing the efficiency of buildings and reducing the demand for energy remains a priority - this is a key element of our Energy Efficient Scotland Programme. This Programme includes commitments to reduce heat demand in domestic buildings by 15% by 2032, and by 20% in non-domestic buildings, eliminating a key driver of fuel poverty. Projects which deliver low carbon gas and substitute existing gas demand are likely to be an efficient way of decarbonising.

Preparing the evidence for a long term future

Beyond the partial decarbonisation of gas we expect during the 2020s, the CCC suggests that even large scale partial decarbonisation of heat is unlikely to be sufficient to meet our 2050 targets[10].

We need to see strategic decisions made during the next decade on how to fully decarbonise heat, and - as part of that - the long term future of gas networks. This means exploring whether the valuable flexibility and energy storage capabilities that the gas networks provide today can be harnessed in a near zero carbon energy system.

The hydrogen future laid out in our Energy Strategy as one potential pathway to near full decarbonisation of energy by 2050 would see the gas network converting to transport 100% hydrogen. This would mean supporting a wholesale change across the wider energy system to develop the technologies capable of producing large quantities of low carbon hydrogen, including electrolysis and Steam Methane Reforming combined with Carbon Capture Use and Storage.

The technical feasibility and costs to consumers of a hydrogen future are deeply uncertain. Reducing this uncertainty needs to be a priority for everyone involved in the sector, with a need for the gas networks, government and the regulator to play an important role over the coming decade.

The Scottish Government plans to build on our recent support for hydrogen. We are working to publish an interactive mapping tool which charts current hydrogen activity in Scotland and plots specific hydrogen opportunities and hydrogen production potential on a region by region basis.

We will also continue to work with our stakeholders to advance a bold range of hydrogen energy and transport initiatives, with accompanying clear analysis and policy statements on the role of hydrogen in Scotland's economy. We will capitalise on Scotland's unique strengths, skills and capabilities to maximise the role and contribution of hydrogen to Scotland's economy and energy future. More detail on these aspects will be included within our Annual Energy Statement published later this year.

There is a lot of work already underway, particularly focused on the ability to repurpose the existing gas distribution networks. In 2017, Ofgem funded the H21 project[11] to assess the suitability of converting the gas distribution networks to transport 100% hydrogen. This project also highlighted the need to stimulate the growth of hydrogen hubs, where Steam Methane Reforming and CCUS capabilities, or the use of large scale renewable generation combined with hydrolysis, are developed to supply the hydrogen.

The focus in Scotland is on demonstration. SGN is planning to roll out a 100% hydrogen trial network in Scotland in the early 2020s to demonstrate the technical feasibility of distributing hydrogen and to show that it can be done safely and securely[12].

The ACORN project based at St. Fergus is aiming to deliver a demonstrator which will produce hydrogen form Steam Methane Reforming in combination with a Carbon Capture plant. The captured CO2 will be transported using existing redundant pipes to North Sea gas fields for storage. The Scottish Government provided funding for feasibility studies into this project, which is an example of how we will continue to support the development of a hydrogen economy.

Reusing the gas networks for 100% hydrogen will mean ensuring that the pipes, pumps and pressure conversion stations can safely transport hydrogen. The gas distribution networks are increasingly constructed from plastic pipes which are suitable for carrying hydrogen, meaning that much of the distribution infrastructure is likely to be relatively easy to convert from natural gas to hydrogen.

The gas transmission system is different, however. An important piece of evidence - and one that we expect National Grid to develop, as owner and operator of the National Transmission Network - will be the role that the gas transmission network can play in a 100% hydrogen future, and the feasibility and costs of repurposing the network to achieve this.

There are a number of roles that transmission infrastructure can play. These include the continued transportation of natural gas - for or example, to Steam Methane Reforming facilities. We will also need networks to transport the gases associated with CCS to locations suitable for storage or use.

The alternative pathway described in our Energy Strategy - an electric future - could lead to the decommissioning of parts of the gas network. The gas network companies, in conjunction with Ofgem, are best placed to understand the costs of doing so, and they should lead work in this area.

The gas network companies will play a big part in gathering the evidence to inform strategic decisions about the best way to decarbonise heat in the long term and it is important that this remains a central focus of their work over the coming years.

The Scottish and UK governments are working closely together, and collaborating with industry, to ensure that we are in a position to make informed decisions during the 2020s.

Box 6: Converting the gas network to hydrogen

Gas networks have the potential to deliver low carbon hydrogen. In the near term, hydrogen could be blended with natural gas to reduce its carbon intensity. In the longer term, it may be feasible and cost effective to use the gas networks to deliver 100% hydrogen to some or all connected areas.

Blending Hydrogen

Hydrogen can be blended with natural gas and with other low carbon gases. International projects such as the Thüga power-to-gas electrolysers in Frankfurt, Germany show that this is possible today. In Germany, up to 10% of the gas volume can be hydrogen, which - if produced by zero carbon means - can reduce the carbon content of the energy delivered by 3%.

The Hydeploy project at Keele University is planning to trial and demonstrate the safety of up-to a 20% hydrogen mix, decarbonising the delivered energy by around 8%. A 20% hydrogen mix across Scotland, supplied from low carbon sources, could provide decarbonised heat equivalent to the demand of around 280,000 homes. One source of energy for this could be renewable generation, requiring the equivalent of around a quarter of Scotland's renewable generation output in 2016.

Blending hydrogen into the gas mains is likely to be viable at concentrations where existing consumers' equipment can safely burn the blended gas. Trials such as the one at Keel can help establish the percentage of hydrogen that can be used safely.

100% Hydrogen

Converting the gas networks to deliver 100% hydrogen is a much greater challenge. This will require a long term and coordinated programme covering gas transmission and distribution, the production of low carbon hydrogen, and the replacement or adjustment of existing consumer and industrial equipment.

Scotland can lead in this area. SGN is planning to demonstrate a 100% hydrogen gas network in Scotland in the next few years, converting part of the gas distribution network to trial delivering hydrogen. The area around St. Fergus also offers a unique combination of resources which make it suitable for trialling the broad range of technologies needed, including large scale production of hydrogen from natural gas, CCS through existing but redundant pipelines in the north sea, and access to transmission and distribution network assets.

Evidence of the gas networks' suitability to support a hydrogen system will be critical to the strategic government decisions over the widespread decarbonisation of heat, and which we need to see well before 2030.

Producing Hydrogen

We will ultimately need the hydrogen that the networks carry to be produced in a low carbon way. Nearly half of the hydrogen in the world today is produced by Steam Methane Reforming (SMR), a chemical process which converts natural gas into hydrogen, while emitting CO2. This can only be 'low carbon' if combined with Carbon Capture Utilisation and Storage (CCUS); developing the SMR process in combination with CCUS will be central to a long term high-hydrogen future.

Alternatively, hydrogen can be produced via electrolysis from renewably-generated electricity. For example, the Surf and Turf project on Orkney links a 500 kW electrolyser to a community owned 900 kW wind turbine. Scotland's offshore wind capabilities also offer a potential opportunity to harness renewable energy for the production of hydrogen.

Electrolysis also provides an opportunity to link the gas and electricity networks in a more coordinated way. Electrolysers could be fitted at locations where the network is constrained, and where the extra electrical demand they create helps reduce the need to curtail wind power. This could also support efficient cross-network decarbonisation, if the same locations were suitable for injecting hydrogen into the gas network.



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