DOI: http://dx.doi.org/10.7488/era/4072

Executive summary

The need for this research

A key recommendation from research and public engagement on climate action in Scotland is for the Scottish Government to develop a clear and concise vision and map. This will help the public understand the goals and the required actions.

Furthermore, Scotland’s Climate Assembly called on the Scottish Government to create a score card with 10 key performance indicators for climate change in an easily accessible and understandable format.

Aims

This research aimed to understand if a climate change score card and/or route map could be used as a communication method and how it could be developed.

To identify relevant examples and best practice, we undertook a rapid international literature review focused on climate change route maps and score cards designed for a public audience. We analysed how these examples could be applied to the Scottish context. This analysis included workshops with members of the public and stakeholder organisations. We used evidence from our literature review and these workshops to identify the needs, preferences and expectations of the Scottish public and stakeholder groups regarding any potential climate change route map and/or score card. In the final task, we assessed the feasibility of implementing these tools to communicate climate change progress and actions in Scotland. This assessment also considered the availability of data that could be used to inform these tools.

Summary of findings

• We found limited literature on the use and effectiveness of route maps and score cards in communicating climate change goals and actions.
• We also found limited international examples of the use of both tools by national governments and public sector bodies. We identified examples of UK-specific route maps developed in relation to climate change and other policy objectives, particularly in the public sector, and score cards developed by pressure groups and NGOs.
• The public workshops indicated moderate enthusiasm for a visually engaging and descriptive route map. This sentiment was also echoed in the stakeholder organisation workshop, where Adaptation Scotland’s Community Climate Adaptation Route map was highlighted by two participants. However, there were doubts about the validity and usefulness of route maps. Many users felt that these would unfairly place the responsibility for achieving climate change targets on individuals. There was an almost universal lack of interest in a score card as a climate change communication tool from both the public and stakeholder organisations.
• Workshop participants in both groups found it challenging to suggest what metrics should be used in both tools, and where they did, these linked to personally relevant actions. Examples included recycling and Ultra Low Emission Zones (ULEZ). However, in the literature review, we found evidence of applicable indicators that were supported by responses given at the stakeholder workshop. These include the Climate Change Committee’s adaptation indicators and Defra’s environmental indicators.

Our research concluded that a climate change route map and/or score card is most likely not the appropriate means for the Scottish Government to communicate climate change progress and actions to the public and stakeholders. This conclusion is based on the overall lack of support within the workshops for these tools, the lack of evidence on their effectiveness within the literature, and the limited international examples of similar methods. Of the two tools, some evidence that a visually engaging route map could be effective, but this is not conclusive.

Recommendations

We cannot confidently recommend that the Scottish Government use a score card or route map, for the reasons summarised above. However, if the Government wishes to develop these tools, or any other communication method, we have provided recommendations on the key communication principles these should follow.

We found little evidence on alternative approaches to communicate climate change progress and/or goals in Scotland; therefore, we cannot provide recommendations in these areas.

Recommendations on designing any future climate change communication method are summarised as follows:

• Keep it visual – users are much more likely to engage with content presented in illustrations and infographics. The visual elements should be clear and easy to understand and complemented by minimal text narrative to help users understand its content.
• Focus on positive messaging – users are more likely to be engaged and energised to take climate action if they can understand what the positive outcomes will be. Users are less likely to engage with negative messaging, as this is perceived as judgemental.
• Relate outcomes to personal actions – users are more likely to be engaged if they can understand what actions they need to take to achieve wider climate goals/targets; and they will be interested in understanding the cumulative impact of their actions. An example of this messaging could be: “If everyone in Scotland were to forego one car journey per week, we would be 5% closer to meeting our transport emission reduction targets and would improve air quality and congestion by 8%”.
• Emphasise the co-benefits – users are interested in knowing the co-benefits of taking climate change action for them. For example, additional benefits of reducing transport emissions such as improved air quality and health improvements from active travel should be clearly communicated. See point 3 for an example.
• Provide contextual detail for those who want to see it – some users will want to understand the detail behind any climate change goal/target and the actions required to achieve them. This information should be provided alongside any visual communication, rather than within. This will allow those users who want to explore the details to do so, without diluting any visual elements.
• Emphasise roles and responsibilities – to achieve credibility and legitimacy in the eyes of the users, any communication should clearly detail the roles and responsibilities of different agencies in achieving climate targets and goals. This is to reassure users that the actions, effort, and cost of achieving these goals is being fairly shared. Users, particularly the public, believe that the Government and businesses have the main responsibilities in achieving climate change targets, with the public providing a supporting role.
• Consider indicators carefully – develop indicators to help communicate progress towards climate change goals, according to the following principles:
• Choose indicators that will be directly affected by the actions detailed in a route map or score card.
• Emphasise that indicators are not definitive. This will avoid fixation on indicators that could lead to perverse action, which does not lead to environmental benefit.
• Choose indicators that are easy to update in a timely manner; for example, Electric Vehicle registrations where data is released on a monthly basis.
• Choose indicators that are expected to remain relevant as government policy and the wider context progress.

Abbreviations table

Introduction

The Scottish Government’s Climate Change Plan sets out the ambitions to meeting the target of achieving net zero emissions by 2045. Achieving this target will require collective action across local government, industry, and society. Regarding individuals within society, the Climate Change Committee (CCC) estimates that 60% of the changes needed to meet Net Zero will require at least some element of behaviour change (CCC, 2019). Therefore, communicating these changes in a manner that generates engagement and facilitates change is crucial if Scotland is going to achieve its climate targets.

Recent research surrounding climate change messaging and public engagement around public action in Scotland has suggested that the public could find a climate change route map and/or score card useful to communicate the key milestones, required actions and progress found within the Climate Change Plan. This research will establish if either of these communication methods are an appropriate tool in communicating to the public. It will also detail how a climate change score card and/or route map, if feasible, could be developed and used, along with the data needed to inform this and to what extent it is available. Effective communication strategies have the potential to accelerate positive public behaviours and increase buy-in to policies that are attempting to reduce emissions.

Given this context, there is a need to explore in greater depth the usefulness and viability of a climate change route map and/or score card for Scotland. Therefore, this research has explored:

• The capabilities, useability, and best practices of route maps and score cards
• Their applicability in the Scottish context
• The needs, preferences, and expectations of potential users; and
• The feasibility of delivering a route map and score card based on (1), (2), and (3), above.

This research is broken down into the following three stages, as illustrated in Figure 1:

• An evidence review stage, including a literature review to identify the capabilities, usability, and applicability of both tools. This informs the discussion prompts for the engagement stage;
• An engagement stage, including a workshop with stakeholder organisations and five public workshops. This stage identifies the needs, preferences, and expectations of potential users; and
• An assessment stage to assess the feasibility of implementing both tools. This is based on literature from the review stage and information from both workshops in the engagement stage.

Figure 1: Research methodology for assessing the feasibility and requirements of developing a route map and scorecard

Literature review

This section provides an overview of academic literature and relevant examples of route maps and score cards for climate change policy communication and evaluation. We present an overview in relation to capabilities and useability, highlighting best practice to inform the applicability of both resources in the Scottish context. This informed the development of discussion points for the workshops (section 4) to understand needs, preferences, and expectations of potential users in subsequent sections of this report.

Background

Relevant surveys have indicated the public still views climate change as a global emergency (UNDP, 2021; Drews et al., 2022). In the Scottish context, there is public concern over climate change and support for climate change policies, including Scotland’s net zero policies (Scottish Government, 2020b), such as the Climate Change (Emissions Reduction Targets) (Scotland) Act (Scottish Government, 2019) and the Climate Change Plan (Scottish Government, 2020d). Research suggests that Government actions (Hammar and Jagers, 2011; Drews and van den Bergh, 2016; Davidovic and Harring, 2020; Wong and Lai, 2022) combined with effective communication and dissemination (Engler et al., 2021; Nursey-Bray, 2023) can lead to policy support and engagement.

However, recent studies indicate a public lack of understanding of climate change policy terms and the actions needed to achieve climate targets in Scotland (Scottish Government, 2020b; Scottish Government, 2021a). These complexities and uncertainties, as well as the presence of deliberate misinformation (Brulle, 2014), complicate the communication and adoption of climate policies (Budescu et al., 2009; Henderson-Sellers, 2011; Brulle and Roberts, 2017).

We have explored several methodologies in the literature for effectively communicating climate change impacts and policy. For instance, Jones & Peterson, (2017) integrated research findings from climate change science communication with a literature narrative policy framework. Their recommendations include using narratives, tailoring to audiences for relatability, and clearly linking narratives with impacts including risks and benefits. Nursey-Bray, (2023) also states that communications on climate change impacts should be tailored to the right audience, but also highlights that communications must be delivered by trustworthy messengers to be effective.

Similarly, Howarth et al., (2020) encourage the use of narratives to enhance climate science communication and Cameron et al., (2021) explore storytelling methods in addition to visuals in communicating policies. This includes the use of video, text, and maps. Wider studies also conclude that visual storytelling could better improve comprehension (Davidson, 2017; Mirkovski et al., 2019). León et al. (2023) explore social media as a platform and strategy for climate change communications. The authors conclude that including higher levels of interaction in social media strategies remains a challenge but could lead to more effective public engagement.

A study on communicating climate change after COVID-19 (Howick et al., 2020) suggested that a route map identifying clear targets towards net zero policies would aid public understanding of how targets can be achieved. This recommendation was driven by the perceived effectiveness of Scotland’s route map through the COVID-19 crisis (Scottish Government, 2020a). This route map presented various scenarios in the form of criteria-defined phases, with further information on current/future public restrictions through which users could understand upcoming mitigation targets and milestones. The study suggested that route maps can improve communications by providing clear and concise overviews of complex policies. This can aid in the understanding of objectives, key stages, uncertainties, and timelines. Furthermore, Scotland’s Climate Assembly identified a ‘route map’ and an accompanying ‘scorecard’ as potential communication and accountability resources for the Scottish government (Scottish Government, 2021b).

Route maps

The review of resources used to communicate climate change policies revealed that ‘roadmaps’ and ‘route maps’ are terms that have been used interchangeably in the literature to communicate objectives in a metaphorical sense (McGarry et al., 2022). The key features of these tools are their use in identifying objectives and synthesising the main elements of a strategic plan into high-level information. Visual representations usually accompany these tools. Blackwell et al., (2008) present a useful description, referring to route maps as a diverse range of resources used to organise and communicate information related to future plans. However, it is important to note that there is no strict definition of what ‘route maps’ should include, leading to a wide variety in methods employed under this heading.

Capability and useability

Whilst route maps take many forms, they are typically used as engagement tools. Route maps provide contextual information and long-term perspectives in climate policy documents or action plans, outlining key objectives and timeframes.

Notable examples of route maps used for communicating climate change targets include the Roadmap for the Global Energy Sector (IEA, 2021), the Scottish Government’s route map to achieve a 20 percent reduction in car kilometres by 2030 (Scottish Government., 2022) – see Figure 2, the net zero roadmap for the timber industry (TDUK, 2022), and the 2030 route map for water companies (Water UK, 2020). Appendix B of this report presents a list of reviewed route maps, including links for further exploration. The image in Figure 2 presents the aforementioned route map, used to illustrate achieving a 20% reduction in car kilometres by 2030. Figure 2, which shows a descriptive route map, represents the most common type of route map we identified during our review.

Figure 2: Infographic from a route map to achieve a 20% reduction in car kilometres by 2030 (Scottish Government, 2022)

The route maps we identified range from international to local and sectoral-specific applications. Our review revealed that there are limited international examples, with most related route maps coming from UK governments and other public sector bodies. For example, Glasgow City Council published the Circular Economy Route map for Glasgow 2020-2030 (Glasgow City Council, 2020), detailing the vision for the implementation of a circular economy in Glasgow. These public sector documents represent long-term strategies and often detail high-level goals/ambitions and the actions required to achieve them.

There is some variation in the level of detail provided within existing route maps. Some detail specific milestones and indicators, such as the Agricultural Reform Route Map (Scottish Government, 2023), while others simply state a high-level vision, like the Welsh Public Sector Route map (Welsh Government, 2021). These types of route maps have generally been developed within the last decade in response to Local Authorities and other public sector bodies declaring climate emergencies and agreeing to temporal net zero targets. As such, there has been limited scope to explore the effectiveness of either methodology or the effectiveness of route maps in general thus far.

We can consider the key properties of the existing route maps and the overlapping practices between them in the potential development of a route map in the Scottish context. The observed key properties include a general trend of communicating high level climate change policy ambitions, accompanying visual representations, the use of relatable indicators, and time-bound milestones. Most route maps include avenues for further exploration, such as links or supporting documentation, to allow users to find more information where available.

Applicability in the Scottish context

Our review showed that route maps have already been applied by the Scottish Government and Scottish public sector bodies (Scottish Government., 2022; Sniffer, 2023; Scottish Government, 2023). We identified 9 relevant route maps used by the Scottish Government and Scottish public sector bodies that communicate strategic plans for achieving net zero (see Appendix B).

These route maps outline clear pathways using key areas, and milestones, and time bound targets, all accompanied by visual representations. Therefore, the Scottish Government could follow a similar approach in designing a document that outlines the specific objectives, along with the milestones and indicators for the CCP.

This process is well understood and would complement existing documentation. It also enables the inclusion of a broad range of information and detail, enhancing the readers’ understanding of why specific objectives need to be achieved along with an outline of the wider context in which they sit.

If the same approach was to be followed for a climate change route map, key milestones, actions, and targets should be specific, measurable, achievable, and time bound. This is particularly important if they cover an extended period. Any future route map should include visual aids to present data and information in a clear and understandable manner. It may also prove useful to illustrate the interconnections between different actions and how they contribute to overarching goals, as seen in the Community Climate Adaptation Toolkit, (2023).

Limitations

Despite the familiarity of such an approach, there are limitations that should be taken into consideration. The static and informational nature of these documents may not achieve engagement with the public. The documents identified in our horizon scanning exercise vary in length and detail, with some consisting of over 80 pages. Larger documents of this type are highly unlikely to be read in detail by members of the public. For this reason, they may not be effective in communicating climate change objectives, progress, and actions.

Consideration also needs to be given to ‘hard to reach’ groups in terms of accessibility. The reviewed route maps were accessible through the webpages of publishers. This means they may not be suitable for groups who find it harder to access those

The route map approach does not allow dynamic reporting of specific indicators, as the document is produced in a static report form. Whilst this allows a large amount of contextual data to be included, there are issues surrounding updateability and relevance as the wider context changes over time. These issues may limit the ability to communicate key milestones, actions, and progress on tackling climate change to the public. This is because the public is likely to want to track progress against key climate change ambitions over time. To meet this need, a route map would need to be updated on a regular basis to display progress against the overarching themes and indicators identified. Such an approach would be time consuming and perhaps impractical due to the potential complexity of climate change indicators.

The absence of monitoring and the continual assessment of progress in route maps can also raise uncertainties. Monitoring also demonstrates the effectiveness of actions and highlights progress towards policy objectives (ENRD, 2021; UK Government, 2022).

Scotland’s Climate Assembly indicates a need for a score card to monitor and assess the progress towards net zero (SSN, 2022) which can potentially serve as an accountability resource.

Score cards

The available score cards in the literature cover a wide range of fields and sectors. For instance, the health-based score card developed by Beaglehole & Bonita, (2008) assesses global public health based on five areas key to the agenda of public health, and Ahmed & Rajaleximi, (2019), and Kennedy et al., (2013), use score cards and behavioural score cards respectively for assessing credit scoring. The types of score cards available in the literature are dependent on their use cases. Buys et al., (2014), developed a ‘sustainability scorecard’ to enable an informed and holistic assessment of the sustainability of industries based on assigned sustainability scores. On the other hand, Khazai et al., (2018) developed a ‘performance scorecard’ that quantitatively assesses resilience parameters to measure urban disaster resilience, and Peterson St-Laurent et al., (2022) produced an ‘adaptation scorecard’ evaluating climate adaptation projects based on 16 criteria.

Climate change related score cards found within the literature have been used to assess policy commitments and actions of public sector bodies and wider sectors towards achieving climate goals and targets, in an attempt to increase accountability and transparency (McKee et al., 2017).

Our review indicates that there are no climate change score cards developed by national governments or public sector bodies. A possible reason for this would be that it could be perceived as disingenuous for a government to assess its progress against self-developed metrics. This is made more complex by the fact that many score cards use qualitative data in assessment, leading to judgement calls when calculating scores/rankings.

Capability and usability

Score cards typically provide intuitive ranking systems based on selected indicators. The capabilities of score cards are flexible, as ranking/scoring metrics can be applied to a wide range of indicators, and the methodology in determining scores/ranking can be as simple or complex as needed. For example, the organisation Climate Scorecard has a very simple methodology where ‘yes/no’ determiners are used to rank climate change progress across a small range of nations (Climate Scorecard, n.d.).

The Climate Change Performance Index includes a comprehensive range of indicators and assessment techniques, accompanied by a technical report (Burck et al., 2022). Similarly, the Climate Scorecard from the Centre for Biological Diversity Action Fund presents a binary method of assessing Joe Biden and Bernie Sanders’s stated climate policy actions (Centre for Biological Diversity Action Fund, 2020), while Defra, (2019) apply multiple indicators to measure progress towards the targets set out in the UK’s 25 Year Environmental Plan. In either case, score cards typically involve the use of indicators to assess selected themes, with indicators sometimes sub-divided into additional ones for more complex assessments, as seen in Cooke et al., (2022).

While the score card assessments can be subjective (Centre for Biological Diversity Action Fund, 2020; Climate Scorecard, n.d.), some score cards use indicators and metrics which usually relate to datasets used to measure progress against related policies. For instance, Burck et al. (2022) present a Climate Change Performance Index where 59 countries are ranked based on their climate change performance, with an overall score given to each country. This score is derived from four main index categories, GHG emissions, renewable energy, energy use and climate policy, against which each country is individually assessed. A published methodology paper details how scores are assigned to each country by index category. Figure 3 presents the climate change performance index rating table developed by Burck et al. (2022) for 63 countries.

Most score cards provide easy to understand information on progress towards specific climate goals, allowing users to make quick comparisons between the entities that have been assessed. Intuitive ranking metrics and visual representations such as bar graphs (Burck et al., 2022) or traffic light systems (Cooke et al., 2022), allow information to be distilled quickly which could make this tool suitable for members of the public in Scotland who are looking for a rapid overview of progress achieved towards high-level climate goals.

Many of these types of score cards are generally interactive, with some hosted as online dashboards, where users can interrogate certain indicators/metrics if they would like to find out more detail. This allows users to drill down into areas they are personally interested in gaining a deeper understanding.

There is limited evidence to assess the effectiveness of score cards for climate change reporting and communication. Additionally, there are no available assessments of their effectiveness that we can draw upon. However, best practices can be inferred from the key characteristics of available score cards.

Figure 3: The climate change performance index by Burck et al. (2022).

Users typically draw on information from score cards to inform decision-making, as shown by Berke et al. (2015), who develop and test a climate change resilience score card that assessed how local plans in Washington DC (U.S.) and in the cities of Nashua and Norfolk (Malecha et al., 2018) target areas most prone to hazards. The score card evaluated planning documents using categories, including community vulnerability, policy response, and plan integration, to assign scores. The effectiveness of local plans was then assessed by policy makers and, based on the results of the scorecard, the city of Nashua amended its hazard mitigation plan, while Norfolk revised its comprehensive plan.

Score cards that use binary assessment methods might offer greater clarity but can potentially oversimplify complex situations, missing important information and face difficulties when measuring progress without quantifiable metrics. Therefore, although this approach could be easily understood by the public, the Scottish Government might need to supplement it with other evaluation methods to ensure comprehensive tracking of progress against its climate goals.

Limitations

There are potential drawbacks to score cards, include data availability, the potential for subjectivity, and the possibility of overlooking external factors influencing performance and omitting the indirect impacts of policies. Berke et al., (2015) highlight some important additional limitations which should be taken into consideration in the development of score cards, including the reliance on proxy indicators to represent climate vulnerabilities and data availability.

The ranking and scoring methodology utilised in any potential score card will need to be robust and transparent to ensure that the ranking/scoring results are viewed as trustworthy by the public. The majority of score cards publish some information on their methodologies, with varying detail articulating how judgements have been formulated.

Interestingly, an Environmental Audit Committee inquiry on an environmental score card Memorandum from the UK Government (UK Parliament, 2015) highlighted the limitations of environmental indicators, and provided the following cautionary notes against implementing an environmental score card:

• The reasons why indicators change and the levers for influencing them are not always clear. This can limit their value as a tool for making and evaluating policies.
• It can lead to a fixation on indicators rather than underlying issues which might result in perverse action which does not lead to overall environmental benefit.
• It may not be possible to keep the score card sufficiently current to influence policy due to lags in data collection and impacts on indicators.
• The Government will continue to need to prioritise its environmental interventions and priorities may change over time as evidence improves or the political landscape changes. A score card would need to be sufficiently flexible to respond to these changes.

Many of these limitations would also apply to the Scottish Government if they were to look to produce a score card that would provide climate change indicators, which are of a similar nature to environmental indicators.

Data availability for both methodologies

Smeets et al., (1999) present a set of environmental indicators that reflect trends in the state of the environment and monitor the progress made in realising environmental policy targets. This includes descriptive, response, and performance indicators such as GHG emissions, forest and wildlife resources, the concentration of phosphorus and sulphur in water bodies, recycling rates of domestic waste, and state environmental expenditure.

Similarly, Defra, (2019) also published a comprehensive set of 66 indicators describing environmental change that relates to the 10 goals within the 25 Year Environment Plan (Defra, 2018a). This framework includes indicators across 10 broad themes (covering natural capital assets, including air, water, seas and estuaries, wildlife, and natural resources), some of which relate to climate change. This framework shows the condition of these assets supported by available data. For instance, one of the indicators for the theme ‘Air’ is ‘Emissions for five key air pollutants’ which is linked to annually published emissions data. The assessment of change then assesses progress in the reduction of emissions for a date range.

In the Scottish context, the National Performance Framework presents Scotland’s national outcomes based on a range of 81 National Indicators, including economic, social, and environmental indicators (Scottish Government, n.d.). Some environmental indicators included within this framework can also be used to monitor progress against Scotland’s Climate Change Plan (Scottish Government, 2020c).

The Climate Change Committee (CCC) has also published over 100 indicators built around policy needs. These indicators address the risks identified in the UK’s Climate Change Risk Assessment (CCRA) and objectives of Scotland’s Climate Change Adaptation Programme (SCCAP), measuring and monitoring progress in building a climate ready Scotland (CCC, 2019). The indicators developed cover a range of themes, including the natural environment, building and infrastructure, and society, with associated sub themes and indicators.

Potential indicators, along with references to supporting data, are also highlighted in Annex B of Scotland’s Climate Change Plan (Scottish Government, 2020c). The sector policy outcome indicators cover electricity, buildings, transport, industry, waste and circular economy, agriculture, and land use.

We have provided a table of potential indicators in Appendix E.

Similarities and differences

Some similarities and differences exist between route maps and score cards relating to their capability and useability.

Both route maps and score cards have been used as public facing communication tools, and typically use visual representations to distil complex information. However, route maps organise and communicate plans (Blackwell et al., 2008), while score cards are used to monitor and assess the progress towards plans, and in some cases, holding leadership accountable (McKee et al., 2017).

Public sector bodies, mostly in the UK, have developed most route maps communicating climate change policies as a means of engaging with the public on strategies and milestones. In contrast, available score cards have been developed by independent bodies assessing a government’s commitment to its climate change policies.

During our review, we found no instances where both tools have been used simultaneously to communicate climate policy and assess the progress towards it. This is likely due to the differences in capabilities of both tools, their use cases, and the typical creators.

The needs, preferences and expectations of potential users

We have broken this section down into the key questions and themes identified in the research specification. We have assessed and identified the needs, preferences, and expectations of potential end-users of a climate change route map and/or scorecard. The ‘end user’ has been identified as the public in this context.

User needs

Generally, members of the public in our workshops viewed Scotland’s performance regarding climate change progress as fair or reasonable. Scotland was also typically seen as outperforming other countries and other parts of the UK. However, while many felt there is an overarching plan, or that they knew action is being taken, they felt progress is not always visible. Participant responses also noted a need to better communicate progress towards climate change goals, along with the key actions that are happening at different scales and how they link up with existing policy commitments. They were also unaware of what progress was being made.

“On paper it would probably look really good, but when it comes to, you know, hard facts about what they’ve done, or getting done, or intend to do soon, I would have a lot lower score.”

Both the public and stakeholder groups emphasised the need to connect any future climate change communications to personal actions that end users could relate to. This is to understand their own personal contributions to wider goals/progress.

“The bin waste and the food waste, the recycling – I do all that. I have no clue where it goes or what it does. Am I actually making a difference? I just do what the bin says, and every two weeks it gets picked up.”

However, the stakeholders stressed that focus should not solely be on end users to achieve the changes needed, as climate targets are a wider scale issue. Stating that users might find it more meaningful to participate in community actions rather than individual changes.

The public workshops also highlighted a wider desire for more positive framing of communication, stating that existing communication is too negative. It is often perceived as directive, telling people what actions they should take, rather than explaining why they should be taking action. Suggestions provided on positive framing included highlighting co-benefits, such as health and saving money. This was reinforced by the stakeholders who suggested that communicating the positive benefits of achieving targets, such as cleaner air or more abundant wildlife, would encourage change.

User preferences

Within both sets of workshops, we explored the key preferences of end-users regarding a potential climate change route map and/or scorecard. This focused on their preferred communication channels, content, and appearance based on the examples presented.

Communication channels

In the public workshops, despite recognition that a multi-channel approach is needed to reach all demographics, many participants expressed a preference for using social media to find out more about how Scotland is tackling climate change. A range of social media platforms were frequently highlighted as the most appropriate way to communicate, particularly by and for younger groups. Some questioned the value of TV adverts, but suggested alternative uses of TV, such as bulletins after the news in the format of a party-political broadcast, or Covid-style briefings.

“Well, social media is okay, but then it disappears… We’ve just got our third bin and we’ve got information through the post to say what goes in every bin. So, I think it’s a good idea through the post as well.”

Stakeholders suggested that both traditional and modern modes of communication were effective. For instance, participants suggest social media, podcasts, tweets, and emails were commonly used. However, it was suggested that accessibility issues might arise with modern modes of communication and that traditional means of communication could be equally effective.

Scorecard/route map content and appearance

Public groups showed a clear preference for simple tools which are not overwhelming and help people engage and understand the information quickly. In spite of this, there were frequent calls for more information to be available about why, when and by whom each policy or plan is being implemented. Suggestions for how this demand for more information could be accessed without overloading a simple tool included:

• Breaking down a visual roadmap or score card into separate elements which could be used in social media posts or posters.
• The potential for a website, platform, or hover-over functionality to provide more information, though few respondents spontaneously called for a large website or dashboard, presenting them with detailed information.

Of the three examples presented to participants, there was a clear preference for a visually engaging route map such as the ‘Transport Scotland route map to achieve a 20 per cent reduction in car kilometres by 2030’ (see Figure 2).

This example was widely preferred because it:

• Presents the information in a visually engaging, colourful, attention-grabbing way.
• Highlights clear timeframes and goals.
• Breaks down information into bite-sized chunks and short, concise sentences.
• Includes and distinguishes between legislation and investment.
• Considers accessibility e.g., it is easier to read or digest for dyslexic or neurodiverse individuals or might spark interest in young people.
• Could be adapted or broken down for different channels, such as linearly on a bus, shown in parts at a bus stop, featured in a social media post, or placed on a fridge.

These themes were echoed by stakeholders who commented that visuals in a route map which communicate how different areas can be affected by climate change would be useful. Similarly, the connection between people and nature was identified as useful in aiding the public to understand the relevance of climate change action and targets, with agriculture being a major topic in this regard. Participants also stated that communication styles should be tailored to specific sectors.

‘Trusted messenger’ participants also provided recommendations for the development of route maps, stating that route maps should:

• Lay out actions that communities can take on climate action and be presented in a visually engaging manner and include functionality to interact with the data;
• Explore how existing reporting requirements connect with route maps; and
• Investigate ways to streamline reporting so additional reporting requirements are not placed on public bodies.

However, stakeholders raised concerns over the granularity of a potential route map. It was suggested that a single overarching route map would be useful, but risks either being too complex or too high a level. Having the functionality that allows users to interrogate the supporting data and information and explore different policy areas including buildings, energy, nature, and transport, would be useful. It was also suggested that support needs to be available for access and use, and ways for the public to get involved should be included, such as providing contact details to get involved with a new bike path. One stakeholder who commented summarised this:

“A route map would be useful if it had a simple graphic on the landing page, with the added functionality of being able to interrogate the information further and to provide further context and specific information”

Score cards

Public groups were shown three examples of score cards (see Appendix C). The preferred choice was the Climate Change Performance Index (Burck et al., 2022) (see Figure 3), for a variety of reasons:

• The graph itself is visually engaging, with the colours clearly outlining a ranking and what information is being used.
• The ranking system enabled readers to readily compare the UK’s progress with others.
• It is based on a variety of metrics.
• The key typically made it easy to follow.

Stakeholders did not express a preference for score card content, noting that while score cards could use numbers as an engagement tool, they were not a public facing resource and would provide less value than a route map. A participant referred to score cards as a “political football”, stating that metrics already exist to assess and monitor progress such as biodiversity intactness index used to highlight Scotland’s biodiversity crisis.

1. User expectations

Scorecard/route map content

Members of the public and stakeholders both expressed strong expectations of what a climate change score card and/or route map should look like, if this was to be developed by the Scottish Government.

One expectation raised by the public was the need for greater recognition of the barriers they face in taking action. A lack of, or more limited, services and infrastructure was noted across the groups, but was more frequently raised by those in rural areas. Some challenges included fewer or less frequent recycling facilities, fewer or closing local services such as banks and GPs, meaning travel is required to access the same services elsewhere, and reduced public transport options, which heightens reliance on cars. A route map needs to consider or acknowledge that these issues exist, particularly in rural areas.

“Because it’s alright us sitting here saying we all need to do more, but we all need to be able to do more.”

This was part of a wider dialogue suggesting that any potential route map and/or score card should emphasise the need for a ‘just transition’ and recognise that certain groups are more disadvantaged than others and that the benefits of any change should be equally shared. For example, stakeholders noted that harder to reach groups should be targeted by any communication method. Participants recommend that there should be a balance between the scale of the challenge and the method of communication, focusing on ‘empowering or equipping rather than education’.

This point was further built upon, with stakeholders suggesting that the onus should not be placed wholly on individuals. Stakeholders stated that in implementing route maps, clear roles and responsibilities should be defined for each action and outcome. In making this clarification, further responses from participants suggested making clear distinctions between public and government actions. In fact, a participant suggested that there be a separate route map for the government and the public, showing how a public route map could connect to the government route map.

It was also suggested that national and regional route maps should clearly indicate where people can take part, mentioning the Community Climate Adaptation Route map^[1] as an example of where this has been implemented at multiple levels. The participant noted that, given the public’s interest in what agencies/government are doing, it might be best to signpost the public to resources for community action to avoid conflating the two responsibilities. This is because conflating personal or community action with public or private sector actions could result in more complex plans, which could turn the public off the messaging. It was recommended that simple messages be attached to route maps to avoid such complexity.

Some participants described how a route map could be useful, or the benefits of having one readily available. These included that it would help to provide some reassurance that there is a plan in place, or that action is being taken, and that it helps to provide advance notice of changes and actions which a household might be required to make in the future. It was noted that this helps provide some information for longer-term planning, for example, how long a household might have available to save to buy an electric vehicle.

Metrics

When the public groups were asked about the metrics or information, they would like to see on a score card or route map, only a few issues were consistently or frequently raised. Suggestions included: progress in reducing emissions or carbon footprint; increased use of renewable energy; improved recycling rates; and reduction in use of single-use plastics and driving mileage. Earlier parts of the discussion highlighting the importance to individuals of understanding their own personal contribution, making it clear that a score card might only be of use or interest if it relates directly to what people are doing on a day-to-day basis.

“I think it goes back to it being relatable and the small things and the impact that has. So it’s letting us know the small things that we do and how that impacts and improves things. For me, anyway. It’s got to be relatable to be interesting.”

The public groups also widely agreed that while the Scottish Government or local government may need to provide data, the validity of any tools should be independently assessed. All groups agreed on the need for independent oversight, emphasising that the Government should not be able to ‘mark its own homework’. A few also noted that an external body could help ensure the consistency of data collection and use. Suggestions for who might provide oversight included SEPA, academics and third-sector organisations.

“I think the Scottish Government can collect it, but they do need an outsider to come in and make sure that they’re not making it look like we’re better than we are.”

Stakeholders offered a broader suggestion of metrics that could be utilised by both communication techniques. Stakeholders suggested that it would be important to report progress against key drivers or themes such as transport, agriculture, and energy, as communities want to know how policy is tackling these sectors as well as what real progress is being made.

Stakeholders acknowledged that accessible data and metrics already exist which could be used to develop a route map/scorecard. However, concerns were raised over local and individual understanding of metrics. As such, it would be important to use metrics relevant to the public. Local air quality was given as an example that the public would easily understand and engage with. However, it was also stated that duplication and contradiction with existing metrics should be avoided so as not to dilute or cloud climate messaging. It was also suggested that “perhaps future resourcing should focus on engagement around metrics which could have more impact than creating a scorecard”. We have discussed what these metrics could look like in our recommendations.

In the public workshops, frequently mentioned examples of climate change progress referenced recycling, the introduction of Low Emission Zones, and more renewable energy and wind farms; however, not all participants viewed these developments favourably. Other signs of progress included being a net exporter of power, bike paths, phasing out gas boilers, becoming carbon neutral or net zero, and more electric cars and buses on the road. Although we cannot draw definitive conclusions on why these topics were mentioned, it is possible they were highlighted due to recent public discourse surrounding them.

Summary of workshops

Both public and trusted messenger workshops indicated a need for better communication regarding climate change targets and the actions needed to achieve them. However, it was not indicated that a route map and score card or an alternative tool would be appropriate for this purpose.

The workshops indicate a need for:

• Positive framing;
• Greater recognition of the barriers to individuals taking action;
• Communicating the wider benefits of taking action; and
• Relating climate targets to community and personal actions supplemented by information about why action is being taken.

There was moderate enthusiasm for a route map but a lack of enthusiasm for a score card in both workshops. While the tools can complement each other, overall, there is greater interest in understanding where progress is being made.

There was an overall preference for more descriptive but visually engaging tools with simple, concise text. However, there is still a desire for more detailed information which could be accessed via the tools.

The public and stakeholders found it challenging to suggest what metrics should be used on a scorecard; where they did, these again linked back to personally relevant actions, such as recycling. There was also widespread agreement that any tools should be independently assessed. Concerning the development of a route map and/or scorecard, stakeholders stressed avoiding placing additional burdens on reporting on both local and national governments. This suggests that, should the government proceed with the development of a scorecard, indicators would need to be tied to existing metrics and data sources where available.

Conclusions

Our research has revealed:

• There are no international examples of a climate change route map and or/score card being employed by another national government. Most existing route maps have been developed by UK local authorities and public sector bodies, and available score cards have been developed by independent bodies.
• There is a gap in the literature regarding the effectiveness of route maps and score cards for climate change communication and reporting.
• There seems to be no apparent need for a route map, but there is a moderate preference towards visually engaging yet descriptive route maps. such as the ‘Transport Scotland route map to achieve a 20 percent reduction in car kilometres by 2030’ and the ‘Community Climate Adaptation Routemap’. This aligns with our findings in the academic literature on climate change communication methodologies. Effective climate change communication methods should employ visual presentation methods whilst also creating a strong narrative that conveys clear milestones in an easy-to-understand format.
• There is no need or preference for a scorecard, and there is no indication of specific metrics or indicators that could be applied in the development of a potential scorecard. Participants in the public workshops were more concerned with evaluating and influencing personal actions like recycling, and stakeholders raised concern over how familiar the public would be with reporting metric and indicators.
• There is little indication of what alternative methodology would be effective.

We have suggested a range of indicators that could potentially be utilised if the Scottish Government decides to implement a climate change progress and goals communication tool. This can be found in Appendix E, and has been extrapolated from the findings of the literature review and indications from workshops.

Our research has suggested that there is still the need for improved climate change communication methods. Although we have not been able to identify which methods would be effective, in the recommendations, we have highlighted the key principles we have uncovered that will improve climate change communications. The details of these principles are covered below in section 7.1.2.

Recommendations

One of the aims of this project was to “make recommendations for how the recommendations for a route map and score card could be taken forward separately or in combination in Scotland”. As detailed in our conclusions, we did not find strong evidence that either approach is effective in communicating climate change goals and/or progress.

Therefore, we cannot confidently recommend that either approach is taken forward by the Scottish Government.

Alternative approaches

We found little evidence on alternative approaches that could be taken to communicate climate change progress/goals in Scotland. Therefore, we cannot provide recommendations that explicitly highlight other communication methods that have been successful.

We do, however, note that our research has indicated that there is a need to improve climate change messaging in Scotland. This has the potential to improve public and stakeholder buy in and contributions towards climate change goals and targets.

Based on the findings of our research, we can provide recommendations on how any future climate change communication method, whether it be a route map, score card or an alternative approach, should be designed. These recommendations are summarised below.

Communication fundamentals

• Use visual methods – users of a potential route map/score card are much more likely to engage with its content if it is of a visual nature. The visual elements should be clear and easy to understand and complemented by minimal text narrative to help users understand its content.
• Focus on positive messaging – any future communication method should focus on the positive outcomes/elements of taking climate change action. Users are more likely to be engaged and energised to take action if they can understand what positive outcomes will result from taking these actions. Users are less likely to engage with negative messaging, as this is perceived as judgemental.
• Relate outcomes to personal actions – Users are more likely to engage with a climate change communication method if they can understand what actions they need to take to achieve wider goals/targets. Users will be interested in understanding the cumulative impact of personal actions. An example of this messaging could be: “If everyone in Scotland were to forego one car journey per week, we would be 5% closer to meeting our transport emission reduction targets, and would also improve air quality and congestion by 8%”.
• Emphasise the co-benefits – users are interested in understanding what the co-benefits of taking climate change action will be for them. For example, if reducing transport emissions is listed as a key outcome/goal of a route map/score card, the additional benefits of improved air quality and health improvements from active travel should also be clearly detailed and communicated. See the example in point 3 for an example of how this could work.
• Provide contextual detail, but only for those who want to see it – some users will want to understand the detail behind any climate change goal/target and the actions required to achieve them. This information should be provided alongside any visual communication method, rather than within. This will allow those users who want to explore the details to do so, without diluting any visual elements.
• Emphasise roles and responsibilities – to achieve credibility and legitimacy in the eyes of the users, any communication method should clearly detail the roles and responsibilities of different agencies in achieving climate change targets and goals. This is to reassure users that the actions/effort/cost of achieving climate change goals is being fairly shared. Users, particularly the public, believe that the Government and businesses have the primary responsibilities in enabling climate change targets, with the public providing a supporting role.
• Consider indicators carefully – it will be necessary to develop indicators to help communicate progress towards climate change goals. They should follow these principles:
• Choose indicators where it can be proven that the actions detailed in any route map/score card will directly affect the indicator.
• Emphasise that indicators are not definitive. This will avoid fixation on indicators that could lead to perverse action, which does not lead to overall environmental benefit.
• Choose indicators that are easy to update in a timely manner; for example, Electric Vehicle registrations where data is released on a monthly basis.
• Choose indicators that are expected to remain relevant as government policy and the wider context progress.

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Appendices

Appendix A: Literature review methodology

We conducted a systematic literature review to identify key academic and grey literature relating to various forms of score cards for climate change communication and other public messaging using approved search terms. This was also done to identify sources that provide insights into communication and messaging strategies as well as methodologies that could be adopted to best convey key topics.

The search strategy was developed using identified keywords for four concepts/themes including:

• Public communication in other sectors;
• Climate change for communication and engagement;
• Scottish communication and messaging strategies; and
• Score card and route map climate change topics.

The concepts were searched using keywords and related search terms in the Google Scholar and Scopus database. Some inclusion and exclusion criteria were applied to ensure the review remained objective such as a date range between 2023 and 2011 to identify the most relevant and recent literature, however, a forward and backward snowballing process was also adopted, where relevant cited papers within papers were also used to inform the literature review. The inclusion and exclusion criteria were also based on publication titles, abstracts, and full text screenings, as well as key word exclusions. For example, there is some overlap between ‘balanced scorecard’ and ‘scorecard’.

The literature search returns frequently included reference to the ‘balanced scorecard’ approach. The ‘balanced scorecard’ approach is a framework developed by Kaplan & Norton, (1992) to translate strategies and mission statements into specific measures and goals in a corporate setting. The methodology for using a BSC involves developing critical measures for four perspectives in an organisation, usually financial, customer, internal progress, and learning and development (Kaplan and Norton, 1996). The BSC is a management and strategy framework, and does not resemble the type of score card being explored (Figure 3, for example). As such, evidence in the academic literature of the use of score cards specifically for climate change communication, which could inform the methodologies used for identifying KPIs to better communicate polices, was limited.

Boolean operators such as “AND” and “OR” were used to search between keywords and related search terms, and the minus sign “- “, was used to remove excluded keywords and search terms.

Appendix B: Evidence review of existing score cards/route maps

Appendix C: Public workshop

Five discussion groups were held with the general public between 21st and 30th August 2023. Each group was 90 minutes long and attended by six members of the public; 30 people took part in total.

Quotas were set across the total sample to ensure it was broadly representative of the Scottish population. However, it was agreed that it would be split equally between urban and rural participants to ensure rural views are considered. The quotas were:

Participants were recruited by Taylor McKenzie Research on behalf of The Lines Between, using a recruitment screener which was agreed by all parties. Groups were facilitated by The Lines Between.

Introduction – 20 mins

First, I’d like us to do a little exercise and introduce ourselves.

I’d like you to take a couple of minutes to think about how you would rate Scotland’s progress so far in tackling climate change.

I don’t mind what sort of rating you use, as I’d like to hear it in a way that makes sense to you.

I’d also like you to explain why you’d give it that rating. You might only want or need to give one or two reasons, but I’d like to hear what you think we’re doing well or not so well.

After a couple of minutes, I’d like to go around the room and ask everyone to:

• Tell us your name and where you are from.
• Give us your rating of Scotland’s progress.
• Explain why you have rated Scotland’s progress as you have.

[NOTE: this exercise will allow us to set the scene with each group but also understand:

• What specific metrics are most important regarding climate change in Scotland.
• What sort of rating scales they see as useful e.g. some may do a scale of 1-10, some Excellent to Poor, etc).
• The wider context of how well they think Scottish Government is currently performing.]

How would you prefer to be informed about the Scottish Government’s progress against climate targets?

• Who should evaluate what they are doing?
• What format would you like to see progress in?
• What is the best way to hold the Scottish Government to account for its climate change targets?

Route maps – 30 mins

One of the two things we want to look at tonight is the idea of a routemap, which could also be known as a roadmap or a pathway.

The aim of a routemap is to provide a clear and concise plan to help everyone understand what’s happening, what the endpoint is, and the actions or journey that needs to happen to get there. It should be able to communicate:

• What are the targets or goals of a policy or strategy
• What actions are needed for those targets can be achieved
• What timescales, milestones or order the changes need to happen in
• Any connections between or consequences from taking action

I’m going to quickly show you a few examples:

Guidance routemap – could be more visual or storytelling about the path or journey, or using accessible visuals and wording

• A route map to achieve a 20 per cent reduction in car kilometres by 2030 | Transport Scotland
• Net zero carbon status by 2030: A route map for decarbonisation across the Welsh public sector (gov.wales)

Descriptive routemap – provides contextual information and long-term perspectives in climate policy documents or action plans, outlining key objectives and timeframes.

• RoutemapToNetZeroCarbonFinal.pdf (churchofengland.org)

Which of those examples do you prefer? Which resonate with you?

Does anyone feel they have seen anything like this before:

• About climate change?
• From the Scottish Government on another policy area?
• From another government or organisation about another issue?

IF YES: Probe for detail on the topic, what was included, and why useful / not.

What would a climate change routemap look like to you?

• What format would be most engaging?
• Would the examples I showed you work? What would need to change?

What information would you like to see in a routemap that would be useful in helping you or other people understand:

• What the Scottish Government is doing?
• When changes are going to take place?
• Your role in tackling climate change and helping you to plan what actions you might need to take?

Score cards – 30 mins

Moving on now, I’d like to talk about a Scorecard. By this, I mean a tool which would provide you with an easy-to-read assessment of how effective the Scottish Government’s climate change policies, strategies and actions have been. The aim would be to have something clear, trustworthy and easy to understand, though there are potentially lots of levels of detail.

I’m going to quickly show you a few examples:

• Climate Change Performance Index: https://ccpi.org/wp-content/uploads/CCPI-2023-Results-3.pdf
• Cooke et al., (2022) assesses the progress of UK professional and regulatory organizations in tackling climate change.
• The Green Central Banking Scorecard scores and ranks the range of green policies and initiatives adopted by G20 central banks. https://greencentralbanking.com/scorecard.

Which of those examples do you prefer? Which resonate with you?

Can anyone think of any other examples, not necessarily climate change, that you have found useful?

Let’s think about what a climate change scorecard might look like for you.

We’re going to do another exercise. I’d like you to consider what actions, steps, targets or data you’d like to see included on a scorecard that monitors Scotland’s progress. There could be up to 10, but it’s absolutely fine if you can’t think of as many as that. I’ll give you a few minutes to think about what you’d like to see, and if you could type them in the chat. However, don’t send them – I’ll tell you when we can all send them together at the end of the exercise.

Talk through metrics and reasons for including them.

Who should decide what indicators are included?

Who should produce the scorecard? Scottish Government, or someone else?

• Who would you want to hear from? Who would you believe?
• Who should provide the data for the scorecard?

How frequently should it be updated?

Would it be useful to compare Scottish progress against other nations?

Finally, I’d like to ask about your preferences for the format of a scorecard.

Would you prefer:

• A focus on data (e.g. numbers and comparison with targets) or a more visual or storytelling approach?
• How do we represent progress? For example, Red/Amber/Green status, Yes/No if met, or quantitative data.
• Would you prefer to view progress against high-level targets (e.g. for the country as a whole) or more sector-specific objectives (e.g. energy, transport)? 
• Would you prefer an interactive dashboard with less detail or a static dashboard with more detail?

Thank and close – 5 mins

Thank you for attending the session today; your time and input is greatly appreciated. We will arrange a £60 payment to each of you as a thank you.

Regarding the next steps, today’s discussion will be transcribed, and the key themes and statements will be extracted and compared to the findings from other participants. These will form the basis of our report to the Scottish Government

Route map samples

Figure 4 -The Scottish Government’s route map to achieve a 20 per cent reduction in car kilometres by 2030 (Scottish Government, 2022)

Figure 4 displays the Scottish Governments route map to achieve a 20 per cent reduction in car kilometres by 2030. It displays a linear routemap beginning in 2021 and ending in the target year of 2030. Key milestones are represented, along with the associated actions that will be implemented to achieve these milestones. For example, the early 2022 milestone includes a commitment to provide free bus travel for those under 22 years of age.

Figure 5: The net zero carbon status by 2030: A route map for decarbonisation across the Welsh public sector (Welsh Government 2021).

Figure 5 shows the transport page of the Welsh public sector route map for decarbonisation. It sets outs the key principles that the Welsh public sector will undertake to achieve net zero in transport. A broad timescale for action is displayed on the left of the image, ranging from ‘Moving up a gear 2021-2022’ to ‘Achieving our goal 2026-2030’. On the right of the image, short sentences describe the key objectives of the route map, such as a commitment to increase the utilisation of active travel in the public sector.

Figure 6: The Church of England’s Route map to Net Zero Carbon by 2030 (The Church of England, 2022).

Figure 6 shows the ‘kind of change that is needed’ section of the Chuch of England Routemap to Net Zero Carbon. It shows key milestones that need to be achieved and the target date for when they will be achieved. A brief introduction to the key milestones is included on the left of the image. A table of milestones is presented to the right, including a description of each objective alongside a target date for when each will be implemented.

Score card samples

Figure 7: The climate change performance index by Burck et al, (2023).

Figure 7 shows the ranking table from the Climate Change Performance Index, with nations given a score out of 100 based on a different range of index categories (such as GHG Emissions). Each country is given (from left to right) an overall ranking (including a low to high rating) , score out of 100 and index category scores.

Figure 8 The score card for assessing organisational climate change policies by Cooke et al., (2022).

Figure 8 displays a score card that assesses different organisations on their climate change policies. Each organisation is given a score based on their policies regarding to elements such as their decarbonisation plan. The different assessment criteria are given on the left and the organisations assessed are given on the top. An overall score out of 11 is presented at the bottom, with the body of image showing green, amber and red indicators where each assessment criteria has been applied to each organisation.

Figure 9 The Green Central Banking Score card (Green Central Banking, 2022)

Figure 9 shows the ranking page of the Green Central Banking scorecard. Each country has been assessed on certain indicators, such as Monetary Policy, which are added together for an aggregate score out of 130. The image displays, from left to right, the country assessed, aggregate score, grade and the score for each of the assessment criteria (Research and Advocacy, Monetary Policy, Financial Policy, Leading by Example).

Appendix D: Stakeholder workshop discussion guide

The stakeholder workshop consisted of the following organisations agreed with the steering group to represent ‘trusted messengers’ regarding climate change. The workshop consisted of 9 organisations and lasted 1 ½ hours. The organisations that attended are listed below, along with the discussion guide.

• Creative Carbon Scotland
• Energy Saving Trust
• Highlands Climate Hub
• Improvement Service
• Royal Society for the Protection of Birds
• NatureScot
• North East Scotland Climate Action Network
• Scottish Communities Climate Action Network & Transition Network Hub for Scotland
• Sniffer

Step 1 – Introductions

Short round of introductions from both workshop organisers and attendees

Step 2 – Summary of research project aims

Short summary of the research aims

Step 3 – Summary of the findings from the public workshops

Short summary of the headline findings from the public workshops

Step 4 – Questions

Set of questions to prompt discussion on key points.

1. How do you currently communicate climate change goals and progress to the public?

• What information would be helpful in your communication with the public?
• How would you make that information land the most effectively and what methods would you utilise?

2. Do you need information/tools for influencing behaviour or reporting on progress (or both)?

• How do you ensure that they motivate and encourage action?

3. What value would a climate change route map and/or scorecard have in your organisation?

• Do you, or other organisations you are aware of, already have or use either?
• Would you use one within your organisation to communicate on climate change?
• Do you think a route map/score card is the best method to fill current information gaps?

d. Do you think there is a more effective way of communicating climate change progress/ambitions?

• Do you make a distinction between a route map/scorecard or see them as a complimentary method?

4. We’ve identified concerns around lack of positive communication, wider responsibility and wanting to know more about personal contributions.

• Do you think a route map/score card would address those issues?
• If not, what would?
• How could a route map or score card be used to communicate a positive or incentivising message?
• Would there be a more effective way to provide feedback on personal contribution to public other than a route map / score card?
• How do we make both tools as relevant as possible to individuals and their daily lives / actions?
• What metrics / issues have you found to be of most interest to the public in your work?

5. Feasibility to inform Phase 4 of the study.

• What metrics do you think would be most effective in communicating climate change progress goals/progress?
• Which bodies would provide the best independent oversight?

Appendix E – Potential indicators and their viability

As the workshops did not provide a clear preference regarding indicators that should be included in a potential scorecard, it was challenging to develop relevant indicators informed by stakeholder and public involvement. However, we provide a list of potential indicators based primarily on the literature review and proxies relating to responses during the workshops below. Indicators were also selected based on existing targets included in relevant UK and Scottish policies, such as Scotland’s Climate Change Plan, as a means of providing reference measurements where progress can be assessed. Therefore, the indicators suggested are intended to act as performance indicators following description by Smeets et al., (1999).

It is important to note that the indicators provided are not a representation of the preferences from the Scottish public and only serve as points of consideration if the Scottish government were to go forward with the development of a scorecard.

The table below presents the summary of potential indicators, their data sources, and the selection bias.

Table 1 Summary of potential indicators

If you require the report in an alternative format such as a Word document, please contact info@climatexchange.org.uk or 0131 651 4783.

© Published by LUC, 2023 on behalf of ClimateXChange. All rights reserved.

While every effort is made to ensure the information in this report is accurate, no legal responsibility is accepted for any errors, omissions or misleading statements. The views expressed represent those of the author(s), and do not necessarily represent those of the host institutions or funders.

info@climatexchange.org.uk

+44(0)131 651 4783

@climatexchange_

www.climatexchange.org.uk

1. https://www.adaptationscotland.org.uk/how-adapt/tools-and-resources/community-climate-adaptation-routemap ↑

DOI: http://dx.doi.org/10.7488/era/3637

Executive summary

Background

Decarbonising heating systems in buildings is an important step towards achieving net zero by 2045 in Scotland. The Heat in Buildings Strategy (Scottish Government, 2021a) outlines the steps planned to achieve this. The Scottish Government anticipates that one million zero carbon heating systems will be needed in new and existing homes by 2030, many of which will be heat pumps. This represents a major challenge because only 3,000 heat pumps are being installed each year in Scotland (Scottish Government, 2021b).

The higher upfront cost compared to gas boilers is a challenge for increasing rollout of heat pumps and effective financing options are required to enable this. This report identifies how innovative business models, such as subscriptions including payment plans, financing and ‘heat as a service’ models, could support the rollout of heat pumps by helping with the upfront investment, which is often a challenge for consumers.

Through a literature review and analysis, and in-depth discussion with stakeholder groups, we explore how three business models could be implemented in Scotland via pilot schemes.

Findings

• A limited number of heat pump finance offerings are currently available to customers in Scotland. Other than an upfront purchase, most of these are finance only payment plans for the purchase of the heat pump only. Uptake for these plans is very low. Funding from the Scottish Government currently includes an up to £7,500 interest-free loan and a grant to the equivalent value. There are heat pump on subscription offerings across Europe, but these are also fairly limited, reflecting an immature market.
• The following range of business models could be applied to heat pumps in Scotland:
• Finance only: Monthly payments and no upfront costs for the heat pump. This can also include routine maintenance, but we have chosen not to include it here. The customer owns the appliance after paying off the loan.
• Financing lease: A leasing scheme with fixed monthly payments that includes routine annual maintenance. ​The customer does not own the appliance.
• Subscription: Similar to financing lease, with the customer paying a monthly fee, which includes a fixed cost per unit of energy or heat delivered.
• Heat as a Service: The provider owns the appliance and delivers routine annual maintenance and breakdown cover, charging the customer a monthly fee to keep the home at an agreed temperature by providing heating.
• Adding the installation of energy efficiency measures, an energy tariff suitable for heat pumps and energy advice to these propositions could increase their appeal.
• There are also non-financial barriers such as complexity of installation, consumer difficulties in understanding fuel bill savings and a current lack of consumer demand.
• Specific barriers to heat pump subscription models include lack of understanding and reassurance around consumer protection and contractual issues – for example, when moving properties.
• Stakeholders have a mixed appetite for piloting new approaches, with the main challenge being provision of finance. Other challenges and risks include ensuring heat pump performance and supply chain capacity.

Proposed business models to pilot in Scotland

We propose three options for pilot schemes that could be tested in a progressive or staged approach. The business models are not expected to generate customer demand for installing heat pumps, but rather to present different financial options in a market where greater customer demand already exists.

• Finance and routine maintenance includes heat pump design, installation and routine annual maintenance through a finance package using monthly payments. This model would build on current market offerings to test the appetite of customers to have a more complete heat pump package by including routine maintenance. It would also test industry interest to launch such a proposition. This pilot could be rolled out fairly quickly if finance can be secured.
• Finance, routine maintenance with energy tariff would ensure customers are on an appropriate energy tariff for a heat pump. This makes the offering even more comprehensive and provides some reassurance around running costs.
• Subscription with routine maintenance and breakdown cover would test the market and consumer appetite for a subscription rather than an ownership model and could include a full maintenance package and potentially a suitable energy tariff. Based on this research, we do not consider the market nor consumers are currently ready for this pilot, but it could be tested in future.

Table 1: Overview of the three proposed business models to pilot

Glossary

Table 2: Glossary

Introduction

This report provides an assessment of, and evidence for, a range of practical and sustainable business models to advance heat pumps on subscription (HPOS) business models at scale in Scotland.

Policy context

The Scottish Government’s Heat in Buildings Strategy (Scottish Government, 2021a) outlines the steps it will take to reduce greenhouse gas emissions from Scotland’s homes, workplaces and community buildings and to remove poor energy performance^[2] as a driver of fuel poverty. Building on the policies and actions set out in the Climate Change Plan Update (Scottish Government, 2021c), the Heat in Buildings Strategy sets out a pathway to zero emissions buildings by 2045 including short and long-term actions to accelerate the transformation of the nation’s building stock. It also sets out the principles the Scottish Government will apply to ensure its zero emissions heat delivery programmes support its fuel poverty objectives.

The Scottish Government aims to double the number of zero direct emission heating systems (ZDEHs) installed in Scotland every year for the next five years and for numbers of installations to reach 200,000 per year towards the end of this decade (Scottish Government, 2021c). This is considered a major challenge compared to the current installation rate of about 3,000 heat pumps each year (Scottish Government, 2021b). The high upfront cost of around £10,000 for an air source heat pump^[3], (LCP Delta, 2022a) compared to gas boilers (~£3,000 – 4,000), means that identifying novel financial models and propositions is essential to unlock the opportunity.

Previous independent research from ClimateXChange (Energy Systems Catapult, 2021) recommended that the Scottish Government undertake further work to explore how Heat as a Service (HaaS) models might support its heat decarbonisation agenda, as well its fuel poverty and economic development goals. There are also potential customer benefits of these models in removing finance barriers and providing ongoing routine maintenance and breakdown cover.

Research aims, scope and methodology

A key principle of HPOS^[4] models is that the responsibility for the provision and operation of the heat pump rests with the supplier. This is believed to address a number of customer pain points but creates risk and uncertainty for the provider, which may impact the commercial attractiveness.

This research aimed to:

• assess the current Scottish marketplace for HPOS;
• draw learnings from case studies within the UK and across Europe;
• conduct interviews with stakeholders to understand the appeal, risks and challenges of these business models in Scotland; and
• identify options for piloting and delivering HPOS in Scotland.

In brief, the methodology for this research included literature review and analysis, and in-depth discussion with stakeholder groups (including business, policy and consumer representatives). Please see Appendix 1 for further detail of our research methodology.

Defining heat pumps on subscription

There are a range of business models that could be applied to support the deployment of heat pumps. This section defines these models and explains how and why they could enable the deployment of heat pumps.

This report uses the term “heat pump on subscription” (HPOS) to refer to the wide range of innovative business models and propositions that could be applied to deploying heat pumps into homes. This excludes an upfront purchase where the customer pays for the heat pump outright.

Finance only

The provision of a financial loan is a natural progression from the standard upfront purchase, where a customer pays in full for the heat pump. In this model, the provider offers finance either directly or, in many cases, using a third-party specialist provider, with the customer repaying the cost of the heat pump and its installation over a number of years and owning the appliance once the loan has been paid off. This proposition can be supplemented with routine annual maintenance, often required by manufacturers to retain the warranty protection.

The principle of using a loan to fund the purchase of a product is fully established and regulated in the market and well understood by consumers. As such, we use this as a baseline proposition to develop more progressive models.

Subscription and leasing models

Subscription and leasing models depart from ‘finance only’ propositions as the provider is responsible for the provision and operation of the heat pump. The customer does not own the appliance and the provider delivers a service to the customer which wraps design, installation, routine maintenance and breakdown cover for the heat pump, usually over a minimum contract term, for a single monthly fee.

This model can also include the cost of energy or heat at a fixed price per unit, although the actual costs are variable and dependent on the amount of energy consumed or heat delivered.

The main attractions of a heat pump subscription model are:

• high initial costs are resolved by ongoing payments which cover product and energy used or heat delivered;
• the service provider owns the product, so appliance performance and technology risk are taken away from the customer; and
• customer pain points of arranging routine maintenance and breakdown cover are owned by the service provider.

These models introduce the fundamental concepts of subscription to consumers and are proposed as an intermediary step towards Heat as a Service (HaaS) offers.

Heat as a Service (HaaS)

HaaS builds further on the key principles of subscription and leasing and includes a commitment to maintain the customer’s property at a given temperature. The supplier owns the heat pump and takes accountability for the operational performance of the appliance as well as the amount of energy consumed to meet the agreed temperature in the home. There is usually some form of penalty levied against the supplier where the agreed temperature is not met. As with subscription and leasing, the features are consolidated into a single monthly customer payment.

The key elements that distinguish HaaS are:

• the customer benefits from a fixed cost solution to delivering heat to their home;
• the supplier is obliged to maintain a heat pump that delivers heat efficiently and reliably;
• the supplier is accountable for any costs arising from poor performance or appliance breakdowns; and
• energy use is based on an agreed level of heat or comfort^[5] rather than units of electricity.

Proposed business models

High initial costs are a significant barrier to increasing the sales of heat pumps (air source heat pumps are typically around £10,000 (LCP Delta, 2022a)) particularly when compared to a standard gas boiler, the default and predominant solution in the UK. The business models identified in this research represent different approaches to resolve this issue by spreading the costs over the contract period.

We reviewed the existing market and used proprietary insight from LCP Delta (2022a) to create four business models for providing heat pumps to consumers, set out in Table 3.

Table 3: Overview of potential business models for providing heat pumps to consumers – categorised into four groups

Table 4 below provides an overview of these four key business models and their features, The table below provides an overview of these four key business models and their features, used for the analysis for this research project. The indicative costs for each model are based on calculations from LCP Delta Heat Research Services (LCP Delta 2022a).

Table 4: Overview of four key business models and their components

Assessment of the Scottish market landscape for heat pumps on subscription

Current examples of heat pumps offerings in Scotland

This section provides an overview of the current market landscape in Scotland for heat pump business models.

Overall, the uptake of heat pumps is still very low in Scotland, with around 3,000 heat pumps installed each year (Scottish Government, 2021b). We found evidence of new propositions being launched, including models incorporating routine annual maintenance, financing options and a tailored tariff (see Glossary for definitions). There are no leasing or subscription models currently available in Scotland. Further details on these offers is provided in this section.

Heat pump offerings in the UK

There are several examples of current heat pump offerings in the UK. Octopus, British Gas, E.ON, Scottish Power and EDF Energy each offer their own proposition (please refer to the summary table of current heat pumps offerings in the UK in Appendix 3).

Overview of offerings

The offers are all variations of an upfront purchase, finance and, in some cases, installation and routine maintenance – there are no HPOS propositions. In all cases, the customer will own the product.

The financial case for heat pumps is weak for a customer in the UK. This is due to the high installation cost of heat pumps compared to gas boilers, and the relatively high price of electricity compared to gas^[7]. There are also other potentially appealing business models, such as green mortgages, where the bank will offer a reduced mortgage interest rate when renewable technology is installed. These were not considered as part of this study.

To complete this research, we also looked at existing dedicated heat pump tariffs in Scotland (a summary table of heat pump tariffs is available in Appendix 3). There is legacy evidence of providers trialling bespoke tariffs, but Octopus is the only supplier currently with a tailored heat pump tariff, which potentially indicates a lack of consumer demand.

Scottish Government support

It is also worth highlighting that eligible households in Scotland can receive financial incentives towards the cost of installing heat pumps through the Energy Saving Trust. This is the Home Energy Scotland Grant and Loan, funded by the Scottish Government, which differs from subsidies available in other parts of the UK. This includes:

• the Home Energy Scotland Grant: £7,500 towards a range of heat pumps. This increases to £9,000 for households qualifying for the rural uplift; and
• the Home Energy Scotland Loan: £7,500 interest-free loan which can be used in combination with the grant. Loans are subject to an administrative fee and can be paid back up to a maximum of 10 years for a £7,500 value^[8].

International examples of heat pumps offerings

We carried out research into the HPOS business models available across Europe. Examples from Germany, Denmark and the Netherlands show a more active market for heat pump business model offers (more details are presented as case studies in Appendix 5).

It is important to consider the specific conditions and context of each country before drawing conclusions around the opportunities to replicate these models in Scotland. In Germany, for example, gas prices are higher than electricity, which means that costs to operate a heat pump are lower than an equivalent gas boiler. There are three providers in Germany offering a rental or lease model which may serve as a positive indicator for the launch of HPOS propositions, although we do not have data on the success of these offers.

While the rental principle is more visible across Europe, only Denmark currently has a full subscription proposition. The Danish example includes the pilot scheme detailed in Appendix 5, where a full subscription model was trialled to support an accelerated roll-out of heat pumps in Denmark. Again, while this pilot was relatively successful, there are several points of difference between the Denmark and Scotland markets. Gas boilers are the default solution to heating in much of Scotland, with a penetration of 85% of households, while less than 15% of Danish households heat their homes in this way. District heating is relatively common in Denmark and the concept of buying heat in MWh is not unusual. Danes are also less likely to have problems paying for their energy because of the protection from their embedded social security and energy regulation provisions. There may also be cultural factors between the countries in terms of consumer acceptability to take on loans or debt, or the preference to own appliances rather than rent them. However, this has not been explored in this research.

Customer and provider insights

This section provides insight from LCP Delta research (2022b) around the customer perspective on different heating business models. The scope of this project did not include a literature review of customer perspectives or to undertake additional customer research. As such, the insights set out here provide an indication of the customer perspective.

The customer perspective

Recent customer research from LCP Delta (2022b) which is undertaken in five of the biggest European markets^[9], showed that ‘alternative finance methods’ like paying upfront, finance only or an addition to an existing mortgage, are more appealing to customers than HaaS. The research highlighted that HaaS is perceived as a more expensive offer. This highlights that there is not currently a consumer demand for subscription models and there may be consumer concerns to overcome.

In the UK, 43% of survey respondents stated that they would choose to pay upfront for a heating appliance, with 20% indicating that they have used a finance option through/from the heating appliance provider. These findings did not relate specifically to heat pumps but heating appliances more generally and, given that gas boilers are lower cost and more popular, it is likely that respondents were thinking about gas boilers when they answered this question^[10]. Interestingly, in the context of willingness to fund heating appliances, people on lower incomes were less likely to want to rent a heating appliance than respondents on higher incomes. The reasons for this are not clear but it may be due to preferences to pay for equipment outright, avoid ongoing payments and attitudes to debt.

Table 5 summarises the indicative costs of a heat pump for a customer specifically calculated for the UK for three alternative purchase methods (LCP Delta, 2022a).^[11] Note that Table 5 has been created for illustrative purposes only and is not the outcome of a fully worked though model. It should also be noted that these costs do not include any government subsidies.

Paying upfront for a heat pump is clearly the least expensive solution over time, but the initial investment cost remains an important barrier for customers. This upfront cost can be avoided by a traditional loan which, combined with a routine maintenance and breakdown package, can provides consumer benefits.

By comparing a heat pump and a boiler finance proposition^[12], the difference in cost between the two types of heating units is apparent. Gas boilers have much lower upfront costs than heat pumps. Reasons for this include the maturity of the gas boiler market and the installation for gas boilers being much simpler and therefore lower cost than heat pumps.

*routine maintenance cost

Table 5: Customer indicative costs for three business models. (Source: LCP Delta 2022a)

The provider perspective

The most common way of selling heat pumps is an upfront purchase for the installation and an annual routine maintenance contract. In this business model the provider receives the profit upfront and there is only a small revenue flow per customer coming from the routine maintenance over the remaining lifetime of the appliance.

Table 6 below presents the difference in revenue for the provider comparing an upfront purchase from the customer and a service-based proposition. In the second, the provider needs to invest in the heat pump installation, but the customer pays it back over a number of years, generating an ongoing and more valuable revenue stream driven by interest payments from the loan.

Table 6: Indicative costs for a heat pump in the UK, comparing upfront purchase and HaaS, Source: LCP Delta (2022a)

Providing a HPOS solution offers providers the advantage of predictable revenue over a longer period of time as consumer contracts will span several years. Providers may add a premium to the monthly fee to cover any default payments, inflation and other risks. However, they are likely to also incur additional expenses (such as customer service costs, billing, remote diagnostics) compared to only selling the product. It takes several years before the provider receives a payback for their investment.

Due to the long timeframes involved, rolling out HPOS at scale would require large capital investment over a sustained period. LCP Delta analysis (LCP Delta, 2022a) shows that the most promising sources of finance for HPOS are likely to be traditional routes such as banks, leasing companies, bonds and investments funds, where long term and recurring income is valued rather than venture capital funds which often expect a more immediate return.

Findings from stakeholder interviews

This section provides results from the stakeholder interviews undertaken as part of this research. The interviews sought to understand stakeholder views to a range of heat pump business models, explore barriers, challenges and the likely success of these models. They also sought to understand the appetite for stakeholders to be involved in a possible pilot scheme in Scotland.

We undertook interviews with a wide range of stakeholders including Government representatives, manufacturers, installers, heat pump industry representatives, financiers, and consumer representatives. A full list is included in Appendix 1 as well as more detailed findings in Appendix 2. An overview of different business models (see Table 3 and 4 in Section 4) was presented to stakeholders as a stimulus for the interview.

Overall thoughts on HPOS business models

Installers acknowledged the potential for HPOS business models but highlighted the risk and impacts to consumer confidence of heat pumps more broadly if a HPOS pilot was poorly delivered. It was felt by stakeholders that all elements of the business model should be robust before HPOS is rolled out.

From a consumer’s perspective, stakeholders felt that HPOS represents a significant change in how households use and pay for their heating. The ‘finance only’ option was identified as likely to be the most attractive option as this was believed to be the simplest for consumers to understand. Including routine annual maintenance and breakdown cover in the package was seen as being key to providing customer protection; a view supported by consumer groups.

From the installer representatives we interviewed, consumer demand is required to stimulate growth in the supply chain. It was felt that leasing and including routine maintenance could improve uptake by reducing upfront costs for the consumers and building consumer trust in the provider. However, it was expressed by stakeholders that a crucial factor in its success will be how the lifetime cost of the asset compares with the consumer’s current heating system. One stakeholder highlighted the advantages of bundling a tariff alongside the heat pump to enable customers to ensure their bills were as low as possible. There was also some anxiety expressed around the possible impact on consumer confidence if a trial was not carefully prepared and executed.

Consumer groups also viewed HPOS as a positive concept, however highlighted that practical difficulties, such as creating a contractual framework that works for both consumer and provider, need to be overcome before this becomes an attractive proposition for either party.

The complexity of the offering for the consumer was highlighted as a key challenge. Stakeholders highlighted that this concept presents to consumers both an unfamiliar technology and payment format. Therefore, interviewees recommended that the contractual side must be very tightly controlled to ensure that consumers are protected.

We also found that product ownership resting with the supplier could be an issue for customers who are not familiar with these models, as well as the commercial opportunity and appeal of such a proposition for a service provider.

The Government representatives we interviewed were broadly supportive of the HPOS concept and acknowledge that subscription models have their place as part of a wider range of financial offerings. They also emphasised the importance of including routine maintenance within the ‘finance only’ option.

Distribution network operators (DNOs) were also positive towards the concept of HPOS, in particular the way in which it can provide consumers with everything they need in one package. Oversight of where installs are occurring was highlighted as important to allow DNOs to overcome the challenges presented to the electricity network from increased electricity demand.

Industry experts understood how the HPOS concept aligned with the macro trend of having access to products and services via a subscription service. It was also felt that the appeal of HPOS will vary across consumers. In a situation where the household would have ownership of the asset at the end of the subscription, HPOS could be an appealing proposition for owner occupiers and the younger demographic as it could add value to their home. For social housing providers this could be less attractive because of the tenant disruption from installation, potential difficulties with subscription fees for a tenant and it is unclear whether the lack of product ownership would be appealing to social landlords.

Challenges and risks

Stakeholders felt that the complexity of the offering presented several challenges for consumers.

Identifying a suitable provider of finance is a key challenge raised by numerous stakeholders. Whilst we did observe a positive response from finance providers who were interviewed, energy retailers did not engage in the process, so we were unable to assess their interest and likelihood to offer such a product.

Consumer lock-in (i.e., that once customers are within the contract, they are prohibited from switching heating system type or provider until the end of the term), was highlighted as a key challenge. It was felt that clarity is required on the contractual arrangements for situations where the consumer’s circumstances change, or they move property.

Unfamiliarity with the technology could make it difficult for consumers to know how efficiently they are using their heat pump and ultimately how much they will be paying for their energy. Minimum performance guarantees were identified as an approach to reduce the uncertainty for consumers, for example a commitment to ensure that the appliance operates as specified for an agreed period, with a payment made to the customer where this is breached. This could be further enhanced with remote monitoring i.e. the provider being able to monitor heat pump performance remotely and potentially being able to diagnose and rectify issues.

Manufacturers highlighted the need to make homes ‘heat pump ready’ prior to rolling out a heat pump uptake scheme. The reason for homes to be heat pump ready in advance is that most heating system replacements are distress purchases (i.e., when their current system has failed, and a replacement is needed reasonably quickly). It is recognised that most distress purchases lead to customers purchasing the same heating system type (e.g., gas boiler). Therefore, carrying out works to homes in advance of a heating system breaking down could help accelerate the heat pump install process.

Consumer awareness and marketing were also highlighted as key challenges that need to be addressed to accelerate demand. DNOs also raised the potential difficulty in recruiting consumers to a potential pilot scheme. A team of coordinators and administrators would help ensure the smooth running of the scheme and that customers receive an appropriate level of support. Installers reflected on the various regulations that are currently associated with renewables and were conscious of the risk of over regulation in this area.

Scottish context

Feedback from consumer groups suggest there are several factors that could present unique opportunities and challenges to the roll-out of HPOS in Scotland, especially in remote areas.

It was felt there is a specific opportunity in rural areas of Scotland where there is no / limited access to mains gas and a high proportion of fuels such as oil, LPG or electricity. Given the higher cost of these fuels and the unregulated nature of oil and LPG markets, heat pumps can be a more financially attractive proposition for households.

Despite this opportunity, concerns were raised by consumer groups on the suitability of Scotland’s housing stock for heat pumps, especially those with lower levels of energy efficiency. This reaffirms the importance of providing energy efficiency measures as part of the HPOS offering.

Consumer groups felt that it was important that both the heating asset and terms underpinning the HPOS agreements are tailored to the climatic conditions in Scotland. A longer heating season and harsh weather conditions in some areas could influence heat pump performance and the cost to the consumer.

In remote areas, poor mobile network infrastructure coverage was also highlighted as a challenge as this could limit the installation of smart meters and reduce the effectiveness of remote monitoring. Finally, a limited number of installers and a nascent supply chain in some remote areas of Scotland could deter investment and lead to long installation lead times in.

Key stakeholders to be involved in a pilot

Due to the infancy of the market, consumer knowledge of heat pump technologies and their use in the UK is not widespread. Consumer groups highlighted their role (alongside manufacturers) to provide independent advice as well as face-to-face education to reduce the information barrier. Well trusted, independent organisations such as Changeworks, Home Energy Scotland^[13] and Citizens Advice were considered to also have an important role in providing impartial advice and support to consumers.

Officials from both the Scottish and UK Governments recognised their roles in raising public awareness of heat pumps and removing regulatory barriers. One stakeholder also noted the role of the UK Government in regulating energy pricing, which in turn would create a beneficial environment for heat pumps. Regarding the role of the Scottish Government, one stakeholder mentioned the importance of ensuring that clarity between any HPOS pilot and existing financial incentives is clear to avoid customer confusion.

To ensure a more cost-effective pilot, DNOs also identified their role in identifying areas of the electricity network that can accommodate increased heat pump deployment (i.e. in some areas the electricity networks have constrained capacity which may impact ability to be able to connect more heat pumps).

For installers, it was suggested that funding would likely be required for small and medium sized installers to overcome the significant initial investment required and improve the rate of return. Installers did not generally see a role for themselves in providing HPOS. However, they felt that if HPOS was rolled out this could be very beneficial for the market, help stimulate demand and provide a clearer pipeline of work for them.

In order to test the scalability of HPOS, stakeholders emphasised the need for the pilot to be comprehensive, ensuring that the concept is tested across a diverse range of participants and property archetypes and ages. A potential sample of 500 – 1,000 households was suggested to achieve this objective and ensure results are statistically valid. This was based on similar pilots. Some stakeholders felt that rather than the overall size of a pilot, the more important aspect was the range of property types and consumer groups involved in order to ensure the model is scalable. Some stakeholders also highlighted the need for the contractual complexities to be well-developed and clear to ensure the pilot is robust.

In terms of evaluation, stakeholders felt that the pilot should capture information on consumer attitudes such as their satisfaction with the install, interest in the pilot and the level of disruption caused by the install. The performance of the asset and estimated versus realised financial savings were also felt important to be recorded.

Some stakeholders highlighted the importance of a robust monitoring and evaluation plan to support households and assess whether the pilot had met its original aims of objectives. Further, some stakeholders suggested this should also be included as a standard part of any HPOS offer, outside of the pilot, to ensure estimated performance was achieved.

One of the main challenges identified with a pilot were the difficulties in recruiting participants and generating sufficient levels of demand, especially given the level of drop out that can be seen. Stakeholders highlighted recruitment lessons from other heat pump or similar projects, such as engaging with community groups.

Other challenges raised included the total cost of the pilot, ensuring the contractor had capacity to deliver and the practical issue of testing the success of a concept that requires long-term binding contract (such as 15 years).

Proposed business models to pilot in Scotland

This section explores what commercially viable and customer attractive business models could be deployed in Scotland. Three concepts for pilot schemes have been created, to address the challenges and hurdles raised in the desk-based research and from stakeholder interviews provided in earlier sections. The business models to be tested in these pilots are recommended by the research team, LCP Delta and Changeworks, in conjunction with conversations with the research steering group. It should be noted that further refinement of some of the practical dimensions of the business models will be required following this research as described in Section 8.4, such as the length of the pilot and number of households to target. These details would depend on Scottish Government ambitions and proposed timings.

There are numerous business models and variations of these models that could be applied. The models chosen here are specifically designed to be practical in terms of feasibility, delivery, and implementation. A progressive approach, as shown in Table 7 below, is recommended, starting with limited but evidence-derived features, and using lessons learnt to be deployed in successive stages.

Pilot 1 focuses on establishing the foundations of the model to overcome consumer barriers and test services that are relatively simple to implement. Pilot 2 builds on this by introducing another single component, a tailored tariff, and finally Pilot 3 consolidates these phases and moves to a subscription model where the provider owns the product.

Table 7: Overview of the three proposed business models to pilot

Overview

We took learnings from the market assessment and created four offers, starting with finance-only product and adding features in each stage, as presented in Table 1. These were used to gauge interest and engagement and to prompt discussion in the stakeholder interviews.

These pilots should be interpreted as broad options for business models that can be tested in Scotland. Note the following limitations and caveats:

• There are many variations and options for each of the three broad categories. For example, they could include optional extras that customers pay for in addition to the standard package but are not compulsory (such as making good a property after disruptive works or in-depth energy advice). They could also run at different term lengths depending on provider and consumer preference.
• Costs presented are indicative only. Actual costs are likely to vary significantly between different property types and customers (and have greater variance than typical costs of a gas boiler). For example, the installation cost of a heat pump will vary depending on the size of the home and the changes needed to the heat distribution system (i.e. radiators and pipework). There are also many factors that could influence the exact payments such as payment terms, interest rates and any add-on services. We have not modelled all of these scenarios as this was not within the project scope.
• Scottish Government incentives, in the form of a grant, have been calculated in Pilot 1 for illustrative purposes. The option to include this will depend on the availability of this grant at the time the pilot is tested.

Pilot 1: Finance and routine maintenance

7.2.1 The business model

Pilot 1 is the easiest to implement and is likely to have broad immediate appeal to customers. The model can be implemented immediately as the heating season is not specifically required for a pilot project because it is not testing product performance and we have already established that heat pumps are a planned purchase.

Overview of business model

Pilot 1 is a finance option scheme providing a complete heat pump solution. This solution includes the following services:

• heat pump system design;
• heat pump installation;
• finance for the heat pump purchase (monthly payments); and
• routine annual maintenance of the heat pump for the duration of the credit which can continue after the appliance is paid.

This model is a natural continuation from the Scottish Government’s Home Energy Scotland support which currently offers customers a £7,500 grant and £7,500 interest-free loan to install a heat pump (with a rural uplift where customers qualify). The models include the addition of a routine annual maintenance solution, which we have established through the research could be a key feature and benefit for customers.

What is being tested

With this model, several questions could be tested:

• Does a straightforward finance option have a greater appeal to a consumer than an upfront purchase?
• Does the inclusion of a routine maintenance package at an additional cost have appeal?
• Is there sufficient interest and engagement from the industry to partner with stakeholders and launch such a proposition?

Customer concerns addressed

This proposal addresses several customer pain points such as the identification of an appropriate installer and access to ongoing routine maintenance. The main barrier it addresses is the upfront payment of the appliance, by offering the opportunity to spread the cost with a loan with monthly payments over 5 to 15 years. Including Scottish Government subsidies, the Home Energy Scotland loan and grant would also reduce the capital sum with the maximum funding amount for a heat pump from these being:

• £15,000 (£7,500 grant plus £7,500 optional loan); and
• £16,500 (£9,000 grant plus £7,500 optional loan if the household qualifies for the rural uplift)

Table 8 shows indicative costs when the £7,500 Home Energy Scotland grant is included^[14].

Table 8: Indicative costs for pilot 1 (finance and routine maintenance) when current Scottish Government subsidies accounted for

This type of model is not strictly an ‘as a service’ offer, as the customer owns the heat pump in full after paying the loan and can extend the routine maintenance service at a cost when the loan period is complete.

Customer and properties to target

Target customers are likely to be the same group that existing offers target, i.e. owner occupiers, able to pay, well informed customers making a planned purchase, but the opportunity to spread payments via a loan removes the significant upfront payment barrier. The addition of routine annual maintenance provides comfort and addresses a customer perception that providers are difficult to engage with. There is potential to extend to social/private landlords and multi tenure dwellings as well as district heating type schemes, but it is very likely that this will create additional complexity around installation, performance and contracting, as well as extending timescales significantly. Vulnerable customers are not excluded as a target customer, but access to credit for the loan finance could be a barrier for them.

It should be noted that appeal for heat pumps more generally is low. While this is expected to grow in future years, customer interest in this model at this stage could be limited.

Stakeholders involved

We would expect this proposition to be offered by a manufacturer or a retailer, likely by partnering with specialists from each sector. The approach requires the collaboration of a wide range of providers:

• appliance provider (most likely a manufacturer);
• finance provider (as retailers do not have the funds for financing, likely to be a third-party finance or a manufacturer of scale);
• installer (the retailer should engage it as a subcontractor as directly employed workforce for retailers is rare because of the costs); and
• maintenance provider (that should be provided by a subcontractor whose costs would be wrapped into the total cost or paid annually).

The benefit for the proposition provider is a potential group of consumers who were previously excluded because of the cost and limited additional risk as they will receive the revenue directly following installation.

From a customer perspective, as evidenced by the stakeholder interviews, a finance option model with at least routine maintenance included is likely to be the most instantly appealing and was also supported by consumer groups.

Indicative costs and revenue flows

Tables 9 and 10 show the costs for such business models without subsidies or grants. They are indicative costs as they were not modelled against specific Scottish property types or consumer profiles^[15].

Table 9 below presents the split of the total cost of a heat pump between the cost of the appliance itself and the installation. This is the lowest cost solution, but the customer must be able to self-fund – it is presented here as a comparison against the finance options considered in Table 10.

Table 9: Indicative costs for “pilot 1” (finance and routine maintenance) without accounting for Scottish Government subsidies

Table 10 below shows an example of a finance purchase method including a finance loan for 5 or 15 years. For the customer, a loan allows the total cost to be spread over a number of years with higher or lower monthly payments depending on the loan period. A loan is more expensive than an upfront purchase but provides the benefit for the customer of spreading the cost and accessing routine maintenance throughout the contract period.

Table 10: Indicative costs for “pilot 1” (finance and maintenance) over different loan periods

7.2.2 The challenges

Pilot 1 is the least complex proposition and provides a measurable baseline against which more progressive and comprehensive propositions can be tested. However, the adoption of this kind of model has challenges, which are:

• Property suitability. This is linked to the energy efficiency measures which may be required in advance of installation to ensure operational efficiency and delivery of heat. As seen in the Danish case study, it is clearly stated that energy service providers are responsible for assessing whether homes are suitable for heat pumps before installing them.
• ‘Making good’ post installation. Customer expectations about the look of their property post-installation (i.e., redecoration, etc) may influence overall satisfaction with the project but this would also be an additional cost to the project. This could serve as an additional costed feature (presented as an optional extra to customers) to encourage sign up.
• Business case. Building a model that addresses risks and generates value for all supplier stakeholders as well as maintaining customer protection is challenging.

Pilot 2: Finance, routine maintenance with energy tariff

7.3.1 The business model

We would suggest Pilot 2 is run after Pilot 1 so that insights and lessons can be implemented. However, the two stages could be run in parallel, if desired, to assess any relative appeal of the additional features.

Overview of business model

Pilot 2 provides a finance option scheme, as per Pilot 1, but with the addition of a bespoke/tailored tariff to support heat pump operation.

What is being tested

With this model, the following issues will be tested:

• Does the inclusion of a tailored tariff with a commitment to be cheaper than a standard tariff have greater appeal to customers?
• Does the introduction of a tailored tariff unlock a new group of customers?

Customer concerns addressed

This model addresses several customer pain points that have already been identified for Pilot 1, the opportunity to spread the costs with a loan and access to installers and provision of routine annual maintenance. As with Pilot 1, inclusion of Scottish Government subsidies would further reduce the heat pump capital cost and related ongoing payments.

A tailored tariff is intended to offer benefits to both the retailer and the customer. The customer is incentivised to shift their demand by being offered periods of lower cost electricity when overall demand on the network is lower. This reduces costs for the customer and offers network benefits.

Customer and properties to target

As for Pilot 1, the target audience would be informed and interested customers who are planning a heating system change, rather than a breakdown prompting a distress purchase. There is potential to extend the target to social/private landlords and multi occupancy dwellings but, again, this will add additional complexity around installation, performance and contracting. Vulnerable customers are not excluded as a target customer for this model, but access to credit could be a barrier to them.

Stakeholders involved

The inclusion of an energy tariff means that this proposition is most likely to be offered by an energy retailer. As in Pilot 1, whoever offers the proposition will need to partner with specialists, such as a manufacturer for providing the appliance, finance providers for financing the appliance and a subcontractor for installation and maintenance.

Overview of tailored tariffs

The tailored energy tariff which matches the operation of a heat pump can be one of the following:

• A Time of Use (ToU) tariff, where a heat pump customer is offered a period (or periods) of low-cost electricity when their system can operate and fill the thermal store ahead of needing it to heat the property or to use as hot water. There will likely be a corresponding period where electricity is more expensive (when there is greater demand or low renewables generation). This would be supported by a commitment that signing up to this tariff would be cheaper than a standard tariff. As described in Appendix 3, Octopus has now launched their CosyOctopus proposition, which offers exactly this. It is currently the only tariff of this kind available in the UK.
• Metered heat should be considered as a logical next step once the principle of tariff plus appliance has been tested. Introducing metered heat would mean the installation of heat meters, which adds a further level of complexity as well as additional costs and risks for the provider. With a metered heat tariff, the supplier bills the customer for the heat provided, rather than for the energy consumed in delivering the heat and is explained further in Appendix 5, using the Danish trial as an example.
• Using heat as a proxy for consumption rather than kWh may also improve understanding for a customer and lead to advanced engagement, although some form of visualisation, i.e., an in-home display or smart phone app may be needed to present this data.

Indicative costs and revenue flows

The indicative costs for this business model are the same as those presented for Pilot 1, and they do not include any subsidies or grants. As for Pilot 1, these costs presented in Table 10 were not modelled against specific Scottish property types or consumer profiles^[16].

7.3.2 The challenges

We find the same challenges in Pilot 2 as in Pilot 1. However, in addition to those, here we are engaging an energy retailer to develop a tailored energy tariff which may increase supplier risk but needs still to be an attractive offer to the customer. The supplier risk is linked to the following issues:

• Energy retailers must embed the risk of building a tariff that accurately reflects the variable cost of electricity at different time periods while also offering a customer price guarantee.
• Implementing tailored energy tariffs requires advanced metering infrastructure, especially for Time of Use tariffs, to accurately measure and record energy consumption in different time periods.
• Introducing Time of Use tariffs requires customer education and engagement from retailers to promote understanding and adoption. Installers could also provide in home support around the efficient operation of a heat pump and how to align with a specialist tariff.

Pilot 3: Subscription with routine maintenance and breakdown cover

7.4.1 The business model

Introducing a subscription model has the potential to unlock a significant new customer segment but introduces a new set of financial and operational risks. The complexity involved in creating a proposition of this type suggests that learnings from Pilots 1 and 2 are essential as well as clearly understanding customer demand.

Overview of business model

Pilot 3 includes a complete heat pump solution, including design, installation, routine maintenance and breakdown cover, with monthly payments to spread the cost over 5 to 15 years. There is a minimum contract term of 5 years that reflects the time to repay the cost of the appliance. An electricity tariff is excluded from this model at this stage, since it is subscription specifically that is being tested, but could be included if insight from Pilot 2 suggests that this is a key feature for customers.

The customer is committed to a fixed term contract and does not own the appliance at the end of the contract. This approach provides the customer with peace of mind, as the service provider would offer a single point of contact for any issues related to their heating system.

What is being tested

With this model, we would like to test several questions:

• Does product ownership influence the customer appeal (as the consumer does not own the appliance at the end of the contract)?
• Is a subscription type product of interest to a customer?
• Is there sufficient industry ambition to launch a subscription type of model?

Customer concerns addressed

In parallel to Pilots 1 and 2, this approach addresses one of the main customer pain points of high upfront costs. A subscription model allows customers to access a heat pump solution with affordable monthly payments over a fixed term, nominally a 15 year period in this model, which also includes routine maintenance and breakdown cover. Customers benefit from a well-maintained and reliable heat pump without the hassle or expenses associated with servicing or unexpected breakdowns.

Customer and properties to target

Target customers are likely to be the same as for Pilot 1 – informed customers who have conducted their own research and are comfortable with the principle of subscription. This could be extended to include social/private landlords and multi occupancy dwellings, but this will add further complexity around installation, performance and contracting. As the market evolves, the insight and lessons learnt from Pilot 1 and 2 can be applied to inform the decision on whether to extend the scope to include vulnerable customers or other target groups.

Stakeholders involved

This model provides long-term, predictable revenue for the provider, although this may be offset by the provision of the upfront capital and the time taken to recover that investment and generate profit. There are also additional expenses to be considered compared to a simple sale, including additional costs for customer service, billing and managing payments, remote diagnostics of the appliance and any interest attracted by loans from an investor or a finance provider. This financial risk was highlighted as a significant barrier by providers. Another concern raised by providers is their ability to offer multiple services from across the value chain (installation, asset management, financing and contracting) as a HPOS model would dictate. Building a consortium with third parties to offer these services was suggested by stakeholders as a solution to support the delivery of HPOS, which is the approach we suggest for the pilot.

We would expect this proposition to be led by a retailer or a finance provider, partnering with experts to deliver specialist services, including:

• a finance provider or manufacturer of scale who can offer finance;
• an installer, likely to be engaged as a subcontractor since a directly employed workforce adds further costs; and
• a maintenance provider, again engaged as a subcontractor, whose costs would be wrapped into the total monthly subscription cost.

Indicative costs and revenue flows

The cost for this model (see Table 11) is wrapped into a monthly subscription fee, initially including the appliance, and then standalone once the product cost has been recovered. We have modelled this pilot to run over 15 years with consistent monthly payments but there are other options. For example, the subscription could have higher initial costs to repay the product more quickly or lower monthly costs but for a longer period.

Table 11: Indicative costs for “pilot 3” (subscription, routine maintenance and breakdown cover)

7.4.2 The challenges

There are several challenges linked to the subscription model. For the suppliers, the challenges are linked to a better understanding of the risks involved and how they can manage those risks to develop propositions that will be commercially viable. A further challenge is how these propositions can be attractive to customers, especially given a lack of product ownership (which we believe – with current customer insights – is not perceived to be an advantage). Understanding customer concerns, is vital to be able to design appealing offerings. Several challenges and questions are raised linked to this proposition:

• Does the subscription model work in the heating sector?
• Does the cost to serve the customer increase in line with longer contract period?
• Does product ownership create a barrier or an opportunity?
• What level of guarantee is offered to the customers once the product is paid off and what is the scope?
• Does this model work for vulnerable customers and is there opportunity to use grant funding to subsidise their costs?

Table 12: Summary table of Pilot schemes

Conclusions

Overview of findings

This research has explored how HPOS business models could be piloted in Scotland. It is anticipated that energy efficiency and climate change policy will drive demand for heat pumps towards the end of the 2020s and beyond. Given their high upfront costs, it will be necessary to help consumers with financing solutions in order to facilitate their uptake.

Our research has described a full spectrum of business models such as ‘finance only’, ‘full subscription’ and ‘heat as a service’ models. Some offerings are currently available in Scotland, but these are mostly limited to ‘finance only’ packages, which essentially provide payment plans to customers wanting to install a heat pump. There is no evidence of the uptake of these offerings, but we believe it to be very low.

There are also a multitude of additional options, alongside financing solutions that can be used to help consumers. Examples include the installation of energy efficiency measures, bundling with an energy tariff and the provision of energy advice.

Results from our desk-based research and stakeholder interviews demonstrate that the Scottish Government should be cautious in forecasting how quickly HPOS could be rolled out in Scotland or indeed how much consumer demand there is likely to be in the near term. Even if finance models are made available to consumers, there are still likely to be non-financial barriers, such as the complexity of the installation and associated costs and timescales, ability of the appliance to deliver sufficient heat without additional insulation, consumer difficulties in understanding fuel bill savings and a current lack of consumer demand, along with wider supply chain issues.

Our research has demonstrated that there is a mixed appetite from all stakeholders for involvement in a HPOS pilot. Challenges and risks such as consumer protection and ensuring heat pump performance were raised by consumer groups and finance providers. The biggest obstacle for organisations who might want to offer a trial proposition was seen to be the provision of finance; only larger companies are likely to be able to provide this and, within this, economies of scale are required to make it attractive.

Specific barriers to HPOS models, which were raised by consumer groups and finance providers related to consumer protection and understanding of contractual issues. For example, many were concerned about product ownership when moving properties. A further key challenge for potential consumers is accessing finance if they already have difficulty in obtaining credit. As discussed in Section 6 of this report, there are multiple issues around providing finance, including a current lack of willingness from finance institutions to enter the market at scale and uncertainty around the ability and willingness of energy suppliers to provide finance packages. As a result of these challenges, the business case for HaaS is currently not strong enough, which has a direct impact on current consumer demand and limits the motivation of finance providers to engage.

A further key consideration is understanding the target customer for different propositions and that a range of propositions may be required rather than a ‘one-size-fits-all’ approach. For example, there may be different levels of consumer appeal to product ownership, but there is a need to test different options to provide an appropriate evidence base. This range of propositions might include a finance plan for those customers that are not able to pay upfront for a heat pump, or a full subscription proposition for those that would like to have a peace of mind (LCP Delta, 2022a).

Overall, our research concludes that there are multiple barriers to all stakeholders in quickly rolling out HPOS models to consumers in Scotland. The consumer demand, supply chain and industry is far from being ready to roll this out at scale. However, we are still able to present options for the Scottish Government to develop HPOS as part of this research.

It should also be noted that the business models presented here are not expected to generate customer demand for installing heat pumps, but rather to present different financial options in a market where greater customer demand exists.

General recommendations

There are many steps the Scottish Government could take to explore, analyse and test HPOS models in greater detail but the best course of action should align with policy development and priorities. Some broad recommendations are made based on this research:

• Build on Scottish Government incentives. The Scottish Government already provides financial support to households through a grant and loan administered by Energy Saving Trust. This report has not considered the uptake, appeal or other factors of this loan as this was not in scope. However, having reviewed the current HPOS business models available in Scotland, we believe that understanding this would be a useful exercise to inform any HPOS pilots. Research with specific customer groups, such as customers who took out the financial support, or who applied and didn’t proceed, may be a useful starting point to test appeal of elements in the proposed pilot business models.
• Clarify regulation including customer protection. Alongside, or before, any initial pilots of HPOS models, further examination, assessment and clarity is needed to aid further development of HPOS models. For example, consumer protection is one of the most important areas for consideration, to examine more fully what customer protection is needed and how customers in different cases may be affected, for instance when they move house. Understanding how HPOS contracts would work in detail may help understand and overcome barriers.
• Build up to more complex and comprehensive propositions. We do not recommend piloting more complex business models such as HaaS immediately. Whilst HaaS could be tested on a small scale, there is very little appetite from industry or customers for this business model and little chance of a large-scale adoption at this point. Instead, we present below a series of staged pilots that would test certain elements of different propositions aimed to overcome specific barriers to heat pump uptake.

Piloting HPOS business models in Scotland

Drawing on the desk-based research, stakeholder interviews and our business model analysis, we recommend three business models to be tested in Scotland:

• Finance and routine maintenance: this includes heat pump design, installation, routine maintenance and a finance package using monthly payments. This model would build on current market offerings to test the appetite of customers to have a more complete heat pump package. This pilot could be rolled out fairly quickly if finance can be secured.
• Finance, routine maintenance with energy tariff: this is the same as package one but includes the bundling of an energy tariff, which would ensure customers are on the lowest possible energy tariff for a heat pump. This makes the customer offering even more comprehensive and provides the customer with reassurance around running costs. Rolling out this pilot would require the involvement of energy suppliers.
• Subscription with routine maintenance and breakdown cover: this model provides subscription rather than a financing model, the main difference being that the provider owns the heat pump and breakdown cover is included alongside routine maintenance. Other elements are the same as pilots 1 and 2, except that there is possibility, coming from the insights of pilot 2, to include a metered heat tariff, which will transform this model into a full subscription one. This business model is more advanced and we do not consider the market or consumers to be currently ready for it, although it could potentially be tested in future.

There are many variations of these models that could be presented and further analysis is required to define the specific features and terms that should be offered. To understand the effectiveness of any pilot requires clear pilot aims to be drawn up and appropriate monitoring and evaluation mechanisms to be implemented.

Stakeholder feedback also highlighted the risks of getting a pilot wrong in terms of potential negative impacts on the industry or negative customer opinions, therefore all elements of the business model need to be robust.

Proposed focus areas for further research

In our research we identified several current evidence gaps that would benefit from further examination.

This research has been conducted without direct feedback from customers on which business models or elements of them appeal the most or why and how this might differ between customer groups. Therefore, the findings and assumptions around customer appeal should be viewed in this context and market research would be needed to understand or test this further. Any pilot study should include an element of customer research to understand customer views. One caveat with undertaking customer research in the near term is to appreciate that attitudes to as-a-service business models may change as the market for these types of propositions grows, both within and outside of the heat pump market.

There are many variations around what specific features are included within each of the models proposed, for example the duration of the contract period, whether a partial up-front payment has appeal, or the type of tariff included in the proposition. Further research focussing on these particular elements may help the refinement of the pilot schemes proposed.

Further research is also needed to understand what consumer protection issues arise with HPOS models and what protection could and should be put in place. In particular, there are questions around the transfer of ownership if a property with a heat pump is sold and any obligation that may be placed on the new owner as well as appropriate regulations to ensure that customers are not exploited with long-term credit contracts.

Building on concerns identified in this research via engagement with consumer groups, we suggest that detailed understanding that directly explored consumer appetite for HPOS and any concerns that may limit uptake would also be of value.

There is also a need to explore what actions should be taken if a customer defaults on payment, or if the customer is vulnerable and unable to pay. This should include what happens to the product that has been installed and how the supplier accounts for this risk.

We also acknowledged that respondents to research questions are often using gas boilers as their reference point when responding to questions around potential models, for example, when asked about the appeal of a subscription service. There may be value in conducting research specifically using heat pumps as a baseline product.

References

Energy Saving Trust, Home Energy Scotland Loan webpage: Home Energy Scotland Grant and Loan: overview · Home Energy Scotland.

LCP Delta Heating Business Service, Ottosson K. and Timperley N. (2022a). Can Heat as a Service (HaaS) drive heat pumps into the mainstream? Can Heat as a Service (HaaS) drive heat pumps into the mainstream? Accessed June 2023. Please note that this report is available to subscribers only.

LCP Delta Heating Business Service, Barquin T. and Cooper C. (2022b). European Customer Research – 2021/2022 – Part 3 – Heating Replacement Trends. European Customer Research – 2021/2022 – Part 3 – Heating Replacement Trends. Accessed June 2023. Please note that this report is available to subscribers only.

Fleck, R., Anaam, A., Hunt, E. and Lipson, M. (2012). The potential of Heat as a Service as a route to decarbonisation for Scotland. Available at: The potential of Heat as a Service as a route to decarbonisation for Scotland Accessed June 2023

Scottish Government (2021a). Heat in buildings strategy – achieving net zero emissions in Scotland’s buildings. Available at: Heat in buildings strategy – achieving net zero emissions in Scotland’s buildings Accessed June 2023

Scottish Government (2021b). Heat Pump Sector Deal – Final report. Available at: Heat pump sector deal – Final Report Accessed June 2023

Scottish Government (2021c). Securing a green recovery path to net zero: climate change plan 2018 – 2032. Available at: “Securing a green recovery on a path to net zero: climate change plan 2018-2032”

Scottish Government (2021d). Heat Pump Sector Deal – Final report. Available at: Heat Pump Sector Deal – Final Report, Accessed June 2023.

Appendices

Appendix 1 Methodology: stakeholder interviews

The methodology focussed on qualitative insights from relevant groups along with analysis of quantitative data. The methods used included:

• Desk-based research to provide an overview of the current market landscape for innovative heat pump business models in Scotland and the international landscape.
• Stakeholder interviews to explore the feasibility of testing HPOS type pilots in Scotland, including an understanding of the barriers, challenges and solutions. This involved 18 interviews with a range of representatives from heat pump installers, manufacturers, consumer bodies, financing organisation, electricity network operations, trade associations and Government. A full list is provided below.
• Analysis of business models which would be piloted in Scotland, drawing on the data above and feeding in information from the research steering group.

Eighteen stakeholders were interviewed as part of this research:

• Industry experts (2)
• Manufacturers (2)
• Consumer organisations (3)
• Trade associations (3)
• Electricity network operators (2)
• Installer organisations (2)
• Financiers (2)
• Government (1)
• Housing association (1)

We also reached out to energy suppliers, but we were unsuccessful in recruiting any for this research in the timescales.

Interviews were semi-structured using a topic guide and interviewees were sent the heating business models developed in this research as a prompt for discussion.

Appendix 2 Findings from stakeholder interviews

Consumer Appeal

The appeal for HPOS will likely vary across consumers depending on their financial situation, awareness of low carbon heating systems and desire to reduce their carbon emissions. Removing the upfront cost of a heat pump will reduce a significant financial barrier to switching to a low carbon heating solution. However, in order to represent a financially appealing proposition, many stakeholders indicated that it is important the running costs associated with heat pumps remain competitive with traditional heating solutions. This is likely to be particularly important for vulnerable consumers, such as those in fuel poverty. It was also highlighted that this consumer group could have more difficulties being accepted onto HPOS due to potentially having poor credit ratings.

Stakeholders highlighted that due to the unfamiliarity with heat pumps and the infancy of these financing models, the total cost of HPOS may not be clear to be consumers. It was therefore considered important that consumers are provided with information on expected heat pump performance and the total cost of the subscription so that they can make an informed decision. This was especially thought to be important for risk averse consumers.

Appeal to providers

The appeal of HPOS to providers is relatively limited, especially amongst small / medium sized installers. This is primarily due to the existence of several barriers that currently deter organisations from offering HPOS. It was felt that smaller installation organisations would need funding in order to overcome the significant initial investment required and improve the rate of return.

Financial risk was identified by installers and consumer groups as one of the main barriers for potential providers. Some organisations may not have access to finance required to cover the significant upfront investment required to offer HPOS. For organisations with the necessary financial backing, the return on investment may not be sufficient to cover the additional credit risk.

The lack of consumer demand creates a challenge for potential providers to justify developing the supply chain and their HPOS proposition. Policy certainty would give providers more confidence on future demand and therefore drive the development of the supply chain. Consumer groups highlighted the role Scottish Government should play in providing clarity on the policy direction for heat decarbonisation in order to drive demand.

Finally, offering HPOS, especially the more advanced business models, requires providers to offer several different services across the value chain. This includes installation, asset management, financing and contracting. Consumer groups highlighted that few organisations would have the capabilities within their organisation to fulfil all responsibilities. Disaggregating the roles (e.g. via subcontracting) was suggested as a way in which different organisations could support the delivery of HPOS.

Almost all stakeholders interviewed felt that small / medium sized organisations are more likely to face the barriers identified above and that larger organisations are better placed to offer HPOS. Multiple stakeholders indicated that only larger companies are realistically going to have the capability and appetite for offering HPOS. It was suggested that large energy suppliers are currently well positioned in the market as they’re able to utilise existing relationships with customers and have access large marketing budgets to acquire new customers. Similarly, there was appetite from manufacturers to deliver or support HPOS rollout. It was felt that the prospect of a consistent payment stream could be attractive to these organisations. Unfortunately, we were unable to recruit an energy supplier to take part in the interviews.

Government indicated that, in order to justify additional investment in marketing and developing their proposition, potential providers need more clarity on the benefits that it could provide to their organisation.

Finance

Installers highlighted the role that organisations such as the Green Investment Group^[17] or the Scottish National Investment Bank^[18] should play in providing finance required to roll-out HPOS. For private investors, the attractiveness of this concept will depend largely on their risk appetite. It was believed by stakeholders that many financial organisations are interested in this but need long term policy certainty.

With regards to fixed term vs rolling contracts, it was suggested that a rolling contract could be preferable for the consumer as it could give providers an opportunity to amend terms or the option to leave if their situation changes. This option would likely be more costly for consumers to reflect the increased financial risk for providers.

Regulation

Stakeholders identified several areas in which changes to existing regulations and future regulations would be needed to support the roll out of HPOS. Currently, energy suppliers in the UK are only able to charge their customers in units of electricity consumed (e.g. p/kWh). In order to offer more complex forms of HaaS, changes to supplier licences would be required to enable suppliers to legally charge a customer for the amount of heat or warmth they receive (e.g. £/warm hours). Furthermore, it was highlighted that if the market is to offer long term contracts, the consumer’s right to change supplier at any point may need to be reviewed.

It was highlighted by several stakeholders that future regulation will be required to ensure consumers are protected. Consumer groups highlighted that if the contractual arrangement is between the consumer and the HPOS provider, then it is believed that the consumer will no longer be covered by Microgeneration Scheme Certification (MCS) protections (the main renewable technology quality standard that is commonly used for heat pump installations). Analysis for this project suggests that this would apply to business models where the customer owns the heat pump themselves and where they have a contractual arrangement with the provider rather than the installer (as it is the installer who is MCS certified)^[19].

Further suggestions included ensuring that consumers are protected from extreme movements in electricity prices, especially those under long term contracts. Government highlighted that a ‘cap on fair usage’ policy, which could enable an upper limit on spend to be set by the customer and send alerts when this limit is approaching, to ensure there is sufficient protection for vulnerable consumers. Regulation is also required to ensure consumers can identify credible schemes to encourage uptake and trust.

Given the length and size of the contracts being proposed under HPOS, stakeholders felt that it would be likely that financial regulation would be required.

Adjustments to current energy market arrangements were also suggested by stakeholders to improve the attractiveness of HPOS. This was commented on in relation to global gas prices being a key driver of the price households pay for their electricity, especially in the UK. Decoupling of wholesale electricity and gas prices is currently being considered by UK Government as part of the wider Review of Electricity Market Arrangements (REMA). Manufacturers highlighted the significance this change could have on stimulating demand for heat pumps by reducing the impact high global gas prices have on the price of electricity, immediately reducing the cost of operating an electric heating asset.

Appendix 3 Heat pumps offerings and heat pump tariffs in the UK

Heat pump offerings

Table 13: Summary of current heat pump offerings in the UK

Octopus Energy has a heat pump offering, “Octopus heat pump” that includes providing and installing a heat pump. Alongside this, customers can choose from two optional service plans, as outlined in table 14.

The British Gas heat pump offering includes a financial option and installation. Their Warm Home Promise offers: a free home survey, industry-leading aftercare, free service in the customer’s first winter and a 5-year warranty and an air source heat pump from the leading brands Vaillant and Daikin. The financial plan from British Gas consists of a 5-years’ interest-free credit which makes the heat pumps more affordable for customers.

E.ON offers different finance options to help customers spread their heat pump cost. These are outlined in the table 15 below. Customers can pay upfront, with a deposit or choose one of the flexible payments options by paying monthly instalments for up to ten years.

Scottish Power is offering an Annual Service Plan for air source heat pumps. Their service includes full testing of the heat pumps equipment and the associated components by specialised engineer for £14.75 per month (one year automatically renewable contract). This service plan is only for air source heat pumps that are owned by the customer and used for personal use.

EDF Energy sales and installs air source heat pumps. Their prices start from £5,500 in England and Wales or £3,000 in Scotland (including the government grant). Heat pumps (Daikin models) purchased and installed from EDF Energy come with a 3–5-year warranty.

The following tables provide more details for the current heat pump offerings in the UK as described in Section 5.1.1.

Table 14: Octopus Energy heat pump offering optional service

Table 15: E.ON heat pump offering finance options

Heat pump tariffs

Table 16: Overview of previous and current heat pump tariffs in the UK

Cosy Octopus is a tariff with double dip Cosy Hours every day: six hours of very cheap electric to warm the customer’s home. To be eligible for Cosy, the customer should have a heat pump (air, or ground source) at a property that Octopus supply. The customer will need a SMETS2 smart meter, or some types of first generation (SMETS1) smart meters, that Octopus can receive half-hourly consumption data from.

OVO Energy announced its trial of its type-of-use heat pump tariff, Heat Pump Pro in March 2022 being the first one of this kind in the UK. Only Daikin heat pump owners living in a Northwards Housing Association property in Greater Manchester were eligible for this trial. OVO Energy new Heat Pump Pro tariff allows members to pay a lower rate for energy used to power their heat pumps. With the Heat Pump Pro tariff trial, participants were getting 5p/kWh off their standard rate for electricity used to power their heat pump. The Heat Pump Pro trial was available for OVO members with a Daikin Heat Pump and smart meter, and who were also on OVO Energy’s Simpler Energy price plan (the variable rate plan). OVO connected the customer’s heat pump to its smart platform and analyse the data it receives from it in order to understand the customer’s central heating system behaviour.

Good Energy had launched a heat pump offer back in 2020 which is not available anymore. The tariff was supposed to help make it more cost-effective to run a heat pump, offering cheaper unit rates at different times of day to ensure consumers can benefit from surplus renewable generation or low demand on the grid.

Appendix 4 Indicative cost for E.ON heat pump offering vs. boiler offering^[20]

Table 17: Indicative costs in a finance proposition comparing heat pump and a boiler

Appendix 5 International examples of heat pumps offerings

Table 18: Overview of current heat pumps business models across Europe

Table 19: Summary of heat pumps business models across Europe

Appendix 6 Examples of other products on subscription

Recently, the UK boiler market has seen the introduction of the boiler subscription service. On average subscription plan is liked to last between 5-10 years. The business model for boiler on subscription might be comparable to the heat pump subscription model, therefore here are some examples of boiler subscription service offerings including the pros and cons.

Table 20: Pros and cons of a boiler subscription offering

Appendix 7 LCP Delta Heating Business Service Customer survey

The Heating Business Service of LCP Delta conducted an online customer survey in December 2021 and January 2022 (LCP Delta 2022b).

Here are the details about the survey:

• Survey respondents:
• ~200 respondents from each of: France, Germany, Italy, United Kingdom, Netherlands
• Homeowners only
• For each country:
• 25% of respondents under 40 years old with annual household income under €40k
• 25% of respondents under 40 years old with annual household income over €40k
• 25% of respondents over 40 years old with annual household income under €40k
• 25% of respondents over 40 years old with annual household income over €40k
• No respondents connected to communal or district heating network
• No respondents under 18 years old

© Published by LCP Delta, 2023 on behalf of ClimateXChange. All rights reserved.

While every effort is made to ensure the information in this report is accurate, no legal responsibility is accepted for any errors, omissions or misleading statements. The views expressed represent those of the author(s), and do not necessarily represent those of the host institutions or funders.

1. The research was conducted in early 2023 and was correct at time of finalisation in August 2023. The market has continued to develop and we are aware of new propositions now available, for example a proprietary heat pump being offered by Octopus and their Cosy tariff. ↑
2. Poor energy performance refers to the inefficient use of energy within a household or building. It often results from inadequate insulation, outdated heating systems, inefficient appliances, and other factors that might lead to excessive energy consumption and high energy bills. ↑
3. This is an average cost for an air source heat pump, but the costs can vary a lot between different sizes of heat pumps which may be required in different property sizes or types. ↑
4. This report uses the term “Heat pump on subscription” (HPOS) to refer to the wide range of innovative business models and propositions that could be applied to deploying heat pumps into homes, as defined in Table 1. ↑
5. When the supplier is maintaining the home temperature at an agreed level. ↑
6. HaaS rather than CaaS was used for analysis in this research given current low cooling demand in Scotland. ↑
7. The financial case is often more positive in areas where there is no gas connection and consumers do not use gas boilers to heat their homes. For example, they may use oil or LPG boilers, or electric storage heaters. ↑
8. The loan available can be defined as a finance only deal; the householder is responsible for securing the installation and maintenance themselves (although some conditions around the installation apply) and owns the appliance. However, the fact that this is interest-free makes it a financially attractive offer. ↑
9. Germany, France, UK, Netherlands and Italy ↑
10. Survey respondents expected their new appliance to be below £4,300, however, air source heat pumps cost around £10,000 (source: LCP Delta Heating Business Service) ↑
11. Available to subscribers only. ↑
12. More details on comparative costs for a finance proposition between a heat pump and a boiler are in Appendix 4. ↑
13. Free and impartial advice funded by the Scottish Government and delivered locally by different organisations, such as Changeworks. ↑
14. Assumptions for the calculations: (1) Upfront purchase of a heat pump estimated at £10,000 with annual service of £130. (2) Interest rate of 4% a year. ↑
15. Assumptions from LCP Delta Heating Business service research as of September 2022: (1) upfront purchase of a heat pump estimated at £10,000 with annual service of £130. (2) interest rate of 4% a year. (3) monthly payments based on offer by Heatio promoted in the UK that never became commercially available. ↑
16. Assumptions from LCP Delta Heating Business service research as of September 2022: (1) upfront purchase of a heat pump estimated at £10,000 with annual service of £130. (2) interest rate of 4% a year. (3) monthly payments based on offer by Heatio promoted in the UK that never became commercially available. ↑
17. The Green Investment Group – The Green Investment Group is an independent organisation whose mission is to accelerate the transition to net zero. ↑
18. Scottish National Investment Bank – a mission-oriented investment Bank in the UK with missions of which achieving a Just Transition to net zero carbon emissions by 2045. ↑
19. A similar case study is the Assignment of Rights (AOR) which was a voluntary feature of the Renewable Heat Incentive (RHGI) scheme. Under AOR, providers installed and owned the heat pump, and received RHI payments when the customer ‘assigned these rights’ to them. Our analysis suggests AOR schemes provided customer protection by providing a zero value contract between the installer and the customer so that the installer still had obligations to the customer. ↑
20. We used E.ON‘s finance options for comparing a heat pump and a boiler offering as they have public data on their website for both offerings. ↑
21. Representative example based on borrowing £10,000 for a new Daikin 9kW air source heat pump, 150 litre cylinder, eight new radiators and an in-home survey, with the £5,000 Boiler Upgrade Scheme grant from the UK government taken off the total price. ↑
22. Based on the average cost of a new boiler installation bought after a personalised consultation, costing £2,900. ↑

DOI: http://dx.doi.org/10.7488/era/3841

Executive summary

Green hydrogen, produced by electrolysis using renewable or low-carbon electricity, is expected to play a key role in the Scottish Government’s net zero emission targets.

The purpose of this study is to determine if Scotland can produce green hydrogen at scale and export it at a competitive cost to the EU market. We explore the costs of producing hydrogen in Scotland, Chile, Norway, Morocco and France and the northeast region of the USA and exporting to northwest Europe, focusing on:

• Production of hydrogen at scale: A large-scale electrolytic hydrogen production plant (1GW) powered by a low-carbon energy source.
• Transport via pipeline: The hydrogen produced is distributed to Rotterdam, where it enters the EU, via either a dedicated pipeline, which transports it from a single facility, or shared pipeline, transporting it from the facility and additional producers.
• Transport via shipping ammonia: The hydrogen produced is converted to ammonia, shipped to Rotterdam and converted back into hydrogen in the Netherlands.
• Transport via shipping compressed hydrogen: The hydrogen produced is compressed to a high pressure and shipped to Rotterdam.

Findings

Figure 1 shows the costs of production and transport per country. From the countries analysed, hydrogen production is cheapest in France given its access to low-cost nuclear electricity. The most expensive is Scotland due to the higher cost of power from offshore wind compared with the other low-carbon power technologies used. Other countries are expected to become more competitive as low-carbon electricity costs reduce and technology improves.

The most cost-effective transport option varies depending on distance, volume, and technology. For longer distances, converting hydrogen to ammonia and shipping via ammonia vessels is most effective. In contrast, for shorter distances, pipeline or compressed hydrogen transport options are more cost-efficient. Pipelines are most cost-efficient when repurposed and the capacity is fully utilised. Where existing infrastructure is not available and the pipeline is not fully utilised, compressed hydrogen shipping offers a cost-saving alternative for shorter distances.

Figure 1 – Levelised cost of hydrogen production and transport (£/kg)

It is more costly to produce hydrogen in Scotland as compared to all other case study countries. This is because the cost of offshore wind generated power in Scotland is higher than the other low carbon power technologies used. In other case study countries, such as France which can produce hydrogen at a significantly lower cost, there could be low carbon power constraints without additional investment in nuclear technology. In contrast, the Scottish Government has set ambition to invest in and scale up its onshore and offshore wind power to enable the growth of its green hydrogen sector.

Exporting hydrogen via ammonia is a feasible option for countries further afield such as the USA and Chile because as distance from the EU increases the costs associated with ammonia shipping movement do not increase significantly. As a result, this allows countries further away from the EU to participate in the hydrogen market. Given the additional costs associated to recovering hydrogen from ammonia, this export method becomes particularly cost effective where ammonia is the end product.

Transporting compressed hydrogen via vessels could be an export method for shorter distances and smaller scale production. However, as the technology is not yet operational, the cost effectiveness and feasibility of this method will need to be further evidenced.

Scotland’s proximity to Rotterdam gives it a competitive advantage because it enables export of hydrogen via pipeline, which is the export option with the lowest cost. In comparison, countries that are further away cannot export via pipeline or compressed shipping due to technical and cost feasibility issues.

To outcompete countries that are closer to Rotterdam, production costs in Scotland must decrease. However, even if the cost of production remains higher in Scotland than in other European countries, Scotland will likely still be a market player as France and Norway alone cannot meet EU hydrogen import targets.

Considering the evolving state of the hydrogen industry, cost estimates for production and transportation carry uncertainty, which affects assessments of market competitiveness.

Recommendations

Government support could close the cost gap and enable Scotland to become a major competitor in the EU market. We recommend:

• Continue to support the scale up of offshore wind and hydrogen production to access economies of scale and enable the generation of surplus low-carbon power for export. Scale up should target a reduction in low-carbon electricity costs as well as capital expenditure for electrolysers (needed for producing green hydrogen).
• Provide subsidies to the sector of between £60m and £500m per year, depending on the export method chosen, to enable Scottish hydrogen producers to outcompete producers who benefit from USA and EU subsidies.
• Valuate the opportunity to repurpose pipeline infrastructure and develop a co-ordinated export strategy with multiple hydrogen producers to maximise use of shared pipelines.

Glossary

Table 1 – Glossary of terms

Introduction

The purpose of this study is to estimate the cost of producing and exporting green hydrogen at scale to the EU market in Scotland compared to other major exporting countries. We have selected the identified exporting countries and the Port of Rotterdam as the key import location into the EU market to, in part, simplify the analysis. We note, as part of a liquid hydrogen market, there will be many exporting countries and import terminals in the EU. These insights will be used to inform recommendations on how the Scottish Government can best support its hydrogen export economy.

Green hydrogen in Scotland

Importance of green hydrogen to a net zero Scotland

In March 2020, Scotland committed to achieving net zero greenhouse gas emissions by 2045 and a 75% reduction by 2030 relative to 1990 levels (Scottish Government, 2019). Hydrogen will play a crucial role in achieving the Scottish Government’s ambition to achieve its Net Zero target by serving as a sustainable energy source for a range of applications. Additionally, hydrogen has the potential to work alongside renewable electricity in reducing carbon emissions in the transportation, power, and industry.

In its 2022 Hydrogen Action Plan, the Scottish Government confirmed its initial ambition to produce 5 gigawatts (GW) of low carbon hydrogen by 2030 and 25GW by 2045 (Scottish Government, 2020a). This would be enough to meet a sixth of Scotland’s energy needs. The most ambitious scenario of the Scottish Hydrogen Assessment estimates that by 2045 Scotland could become a leading exporter of hydrogen (Scottish Government, 2020b).

Scaling up hydrogen production in Scotland

To meet Scotland’s production targets, wind energy capacity will need to be built, hydrogen production and associated infrastructure scaled-up, and early market creation supported.

The Scottish Government’s Hydrogen Action plan aims to achieve a 5GW hydrogen target by 2030, with the majority of this capacity coming from renewable sources. The Scottish Government has stated plans to continue to support the development of onshore and offshore wind projects in Scotland to realise this ambition (Scottish Government, 2022a) as generally the renewable power required is 1-2 times the installed electrolyser capacity.

As of 2022, Scotland had c. 9GW of installed onshore wind capacity and c. 2.2GW of installed offshore wind capacity (Scottish Government, 2022a). The Scottish Government intends to enable the significant ramp up of both onshore and offshore wind energy. For example, in its 2022 Onshore Wind Policy Statement the Scottish Government set an ambition to deploy 20GW of onshore wind by 2030 (Scottish Government, 2022b) and in its Offshore Wind Policy Statement, it set a target to achieve 8–11GW of offshore wind in Scottish waters by 2030 (Scottish Government, 2020c). More recently, the Crown Estate Scotland announced the outcome of the 2022 ScotWind leasing round, with 17 successful applicants being offered option agreements totalling c. 25GW of capacity (Crown Estate Scotland, 2022). Realising this renewable capacity in Scotland will enable the uptake of green hydrogen production.

Increasing the size of green hydrogen production plants will also support the Scottish Government to meet its targets at pace and cost effectively. Larger scale hydrogen production plants can lead to increased economies of scale, particularly related to reduced balance of plant, power electronics, and hydrogen purification costs (IRENA, 2020a). So, Scottish Government’s hydrogen production targets are more likely to be achieved through the development of large-scale projects; however, this needs to be supported by a corresponding scale-up in demand.

Government has a role in enabling early market creation by supporting research, innovation, and commercialisation of hydrogen technologies across a wide range of end uses. It can also develop policy to encourage early use cases. Establishing the early market for hydrogen in Scotland will enable production at scale, which could reduce costs, thereby further unlocking new markets. As the next section explains, export of hydrogen and its derivatives could be an avenue for accessing large scale demand.

Hydrogen production for export

In the Hydrogen Action Plan, Scottish Government established its intention to become a leading producer and exporter of hydrogen and hydrogen derivatives for use in the UK and in Europe with the aim of hydrogen to be delivered to mainland Europe in the mid-2020s (Scottish Government, 2022a). In the longer term, the Scottish Hydrogen Assessment estimates that approximately 3.3Mt (126 TWh) of renewable hydrogen could be produced in Scotland, with 2.5Mt (94 TWh) exported to the UK and European markets annually (Scottish Government, 2020b). Meeting Scotland’s hydrogen production targets and establishing it as a key hydrogen exporter will not only contribute to reducing emissions but has the potential to safeguard industry and employment.

Green Hydrogen in Europe

Importance of green hydrogen to a net zero Europe

Developing a hydrogen sector in the European Union (EU) will enable it to achieve sustainability targets while allowing greater energy independence. The EU aims to achieve net zero greenhouse gas (GHG) emissions by 2050 and a minimum GHG emission reduction of 55% by 2030 (EU Commission, 2022a). As noted, hydrogen’s suitability as a sustainable energy source across a range of sectors means the EU expects hydrogen to play an important role in achieving these targets. Further, geopolitical events have triggered momentum around the development of the EU hydrogen sector and in May 2022, via its RePowerEU plan, the European Commission declared an ambition for renewable hydrogen uptake to enable it to move away from imported Russian fossil fuels (EU Commission, 2022b). Currently, the EU is on track to produce 1 Mt of renewable hydrogen by 2024 and has set the ambition to produce 10 Mt of renewable hydrogen and import 10 Mt by 2030 (EU Commission, 2022b).

Role of imports in meeting hydrogen demand

Centres of hydrogen demand in Europe may not be in the same location as regions with favourable characteristics to produce hydrogen. Given this, there is a need to develop hydrogen transport infrastructure within the continent as well as globally to enable hydrogen to be moved from where it is produced to where it is consumed. The European Hydrogen Backbone initiative seeks to develop pan-European hydrogen pipeline infrastructure to connect demand centres such as industrial clusters and ports to areas of hydrogen production (EU Hydrogen Backbone Initative, 2022). In the near term, it seeks to transport half of the 10 Mt hydrogen production target via five large-scale pipeline corridors including corridors in the North Sea, Nordic & Baltic, southwest Europe, southeastern Europe, and North Africa (EU Hydrogen Backbone Initative, 2022). To meet the European Commission’s import targets cost effectively, the EU may also seek to import hydrogen produced further afield. Despite the additional transport costs, some imports may remain cost competitive particularly in countries with an abundance of cheap low carbon electricity.

Key export countries

The global hydrogen market is nascent. While the announcement of new projects for the production of low-emission hydrogen continues to grow, only 5% of these have undertaken firm investment decisions (IEA, 2023a). However, the market is expected to grow as importing countries seek to meet climate objectives and diversify their energy supply. Many governments have already set targets for hydrogen exports or imports to be reached in the coming decades.

The global trade of hydrogen will require new transport infrastructure, coordinated standards and regulations, and demand creation across multiple sectors in import countries. Hydrogen is expected to be transported globally via a range of technologies including pipelines and shipping vessels. The location of the export countries and status of existing transport infrastructure will dictate the most cost-effective option. Importing countries globally will seek to establish common standards and regulations to allow governments to discern between hydrogen of varying emissions intensities. Importing countries will also need to drive early hydrogen adoption across different sectors including difficult to abate sectors such as industry and heavy transport.

We have chosen to compare Scotland’s competitiveness in the EU market against Chile, Norway, Morocco, France, and the USA. This is because these countries cover a range of geographies, production methods, have appropriate infrastructure and are in good proximity to major EU hydrogen import terminals. While Chile is further afield, its access to an abundance of natural resources, particularly wind, will enable it to produce green hydrogen at scale. The US’s IRA subsidy is expected to accelerate the deployment of green hydrogen in the country enabling the US to become a major producer and exporter of hydrogen.

The export distances to the Port of Rotterdam from each of the case study countries are illustrated in Figure 2.

Figure 2 – Export distances to the Port of Rotterdam for each case study country via shipping and pipeline

Green hydrogen production and export supply chain

This section reviews cost components that will be key input assumptions for the levelized cost model.

Production and export supply chain overview

The hydrogen supply chain can be divided into two main stages. Low-carbon electricity generation to produce the feedstock power for the production of hydrogen by electrolysis. Hydrogen can then be exported by pipeline or by ship. For export by ship, the hydrogen may be converted into more easily transportable forms. Methods currently being considered by the industry include ammonia, metal hydrides, liquified hydrogen, liquid organic hydrogen carriers such as toluene and high-pressure gaseous hydrogen.

We have considered three pathways for hydrogen export, as illustrated in Figure 3:

• Transport pathway 1 – Pipeline: Gaseous hydrogen can be transported via a pipeline cost effectively particularly at large scale. We have considered a range of pipeline export models including via new or repurposed infrastructure and via a dedicated pipeline sized to a GW scale electrolyser and a shared pipeline sized to accommodate the transport of hydrogen from multiple producers.
• Transport pathway 2 – Shipping ammonia: Hydrogen can also be converted to ammonia and transported via dedicated vessels. Ammonia’s higher energy density relative to hydrogen makes it particularly cost effective to transport via ship.
• Transport pathway 3 – Shipping compressed hydrogen: High pressure gaseous hydrogen can be transported via dedicated vessels. Similarly, compressing hydrogen increases its energy density making it more economical to ship. Shipping pure hydrogen rather than a hydrogen derivative reduces additional costs associated with reconversion.

We have selected pathways to provide a wide and representative range of vectors for hydrogen export. We have not considered the transport of hydrogen in liquid form or as liquid organic hydrogen carriers (LOHC). This is because liquid hydrogen as a transport option is increasingly become less cost-effective relative to alternative options. While LOHC offers a reasonable route to export, it has notable similarities to the ammonia and compressed hydrogen pathways. Figure 3 – Schematic of transport pathways considered in this report

Large scale hydrogen production

Low-carbon electricity

Low-carbon electricity is the key feedstock for hydrogen production. The cost of the electricity and the capacity factor of the low-carbon generator are typically the largest contributors to the cost of hydrogen production. We have considered:

• The cost of electricity represented as the levelized cost of energy (LCOE).
• Capacity factor which is defined as the electricity produced in a period divided by the electricity it could have produced if it had operated 100% output for the period.
• Hourly energy production profile per generator for a given year in each case study country in order to size the generation capacity.

We set out the cost of electricity, capacity factor, and assumed generator size per case study country. We have reviewed a wide range of data to inform these inputs and the data presented below represents an informed average. A summary of the current and future assumed costs of electricity per country is shown in Figure 4.

Figure 4 – Electricity price assumptions by country

Offshore wind in Scotland

Scotland has abundant access to offshore wind resources, much of it remote from end users. This is expected to be the dominant power source for large scale hydrogen production in Scotland. We assume the LCOE for Scotland to be £58/MWh currently and £36/MWh in 2045. Similarly, the current capacity factor of offshore wind in Scotland is 55% today and is projected to increase to 61% in future (BloombergNEF, 2023). The size of the low-carbon generator required today will be 1.4GW and reduce in future to 1.3GW to power the electrolyser enabling an electrolyser utilisation of 65% and 67% respectively. The future projections are driven by assumed reductions in capital expenditure (CAPEX) costs due to improved supply chains, reduction in operations and maintenance (O&M) costs due to increased competition of service providers and technological improvements and innovation driven by global learnings (IRENA, 2020b).

Nuclear energy in France

Producers in France may use nuclear energy to generate low-carbon hydrogen. France has one of the largest nuclear power programs in the world, with nuclear power plants accounting for 68% of the country’s annual electricity generation (U.S. Energy Information Administration, 2023). This technology can provide a baseload capacity, ensuring a consistent and reliable source of power that allows for efficient and potentially high utilisation of hydrogen producing equipment (electrolysers).

The LCOE for nuclear in France is £37/MWh which we do not project to reduce in future (IEA, 2020). Nuclear power plants in France have a capacity factor of 85% due to the aging nature of the reactor stock resulting in more outages (IEA, 2020). Given the high-capacity factor, the generating capacity will be the same size as the GW scale electrolyser, resulting in a plant utilisation of 85%.

Hydropower in Norway

Norway has an almost entirely renewables-based electricity system, with low-carbon resources accounting for 98% of generation in 2020, of which hydro power was the dominant source at 92% (IEA, 2022a). This means low-carbon hydrogen in Norway can be produced via grid electricity resulting in high electrolyser utilisation.

Grid electricity prices vary in Norway depending on the bidding zone a customer is in. Zones are regularly redefined by Statnett, the System Operator, and currently Norway is divided into five bidding zones (NO1-NO5) (NVE-RME, 2023). Prices are set daily by NordPool to reflect the current level of congestion in the bidding zone. Prices are lower in zones where there is a surplus of power and higher in zones where there is a power deficit. Bidding zone NO4, which is in the north of Norway, has the lowest electricity prices in the country, due to more abundant wind and hydropower output, with a recent price of between €42/MWh and €50/MWh (Nordpool, 2023). Prices in bidding zones surrounding Oslo, the southern coastal hub Kristiansand and Bergen on the west coast have higher electricity prices of between €80/MWh and €86/MWh (Nordpool, 2023). In 2022 grid electricity prices in all zones increased significantly, driven by low reservoir filling levels in southern Norway and power export cables from the UK to Germany. We have assumed an LCOE of £52/MWh which represents an average of the recent wholesale electricity prices in Norway, and project this may decline in future as the external factors which have caused a recent spike are resolved.

Using electricity from the grid allows producers to run at a constant, maximum capacity factor, equalling their availability once annual maintenance has been considered. Given this, we assume the capacity factor to be 98% resulting in a high electrolyser utilisation rate.

Hydrogen producers in Norway will also incur the cost to connect to the electricity grid. This upfront cost will vary depending on the size and location of the connection. We assume a connection cost of £25,000/MW (Arup benchmark, n.d.).

Onshore wind in Chile

The geographical characteristics of Chile, particularly in the southern Magallanes region, enable access to significant amounts of onshore wind power. Producers will use this technology as their key electricity source.

We assume the LCOE for wind in Chile is £35/MWh which will reduce in future to £24/MWh (BloombergNEF, 2019a). We project reductions in cost driven by reductions in turbine prices and balance of plant costs, greater wind farm operational experience and improved preventative maintenance programmes (IRENA, 2020b). Based on electricity production data in the Magallanes region, the capacity factor of onshore wind in the area is particularly high at 59% resulting in an electrolyser utilisation rate of c.67%. Given the existing high-capacity factor of onshore wind technology in Chile, we project this will not increase significantly in the future.

Solar power and onshore wind in Morocco

Combining multiple low-carbon energy resources, such as solar and onshore wind power, can help reduce intermittent electricity production from a single low-carbon technology. Morocco has good natural resources to enable access to significant amounts of both solar and onshore wind.

We assume the current LCOE of solar in Morocco to be £32/MWh which will decline to £13/MWh in future. The current capacity factor of the technology is 28.8% which will increase to 30.6% (IEA, 2021). For onshore wind in Morocco, we assume the current LCOE is £49/MWh which will reduce to £41/MWh in future. Lastly, the capacity factor of onshore wind technology today is 37% and will improve to 45.9% in future (IEA, 2021). We project price reductions and improved capacity factors for both technologies due to global learnings. Significant declines in the LCOE of solar is driven by declines in module prices and plant costs and scaled up manufacturing capability (IEA, 2022b). The complimentary nature of the combination of solar and wind production enables an electrolyser utilisation rate of 65% with solar generating capacity sized at 1.2GW and wind sized at 1.3GW.

Onshore wind in the USA

In the US, the North East region has been selected as the basis for analysis. Although there are a number of projects and regional hubs exploring the potential to export low carbon hydrogen throughout the US, the North East Hub presents significant opportunities for exports to the EU. In November 2022, New York State Energy Research and Development Authority (NYSERDA) submitted a concept paper on behalf of seven states to be considered and compete for funding to develop a hydrogen hub in the area (NYSERDA, 2023). Given the Northeast’s relative proximity to the EU and this hydrogen hub initiative, we assume production takes place in this region. The USA has good wind resources enabling it to have access to significant amounts of onshore wind power. However, given the land constraints in the region, we assume hydrogen producers procure onshore wind capacity via sleeved purchase power agreements (PPAs). PPAs are contractual agreements between energy suppliers and consumers which enable consumers to procure electricity from a renewable asset without being directly connected to it. Sleeved PPAs are contractual arrangements for large consumers of electricity, such as hydrogen developers. The most prevalent PPA structure is a ‘pay-as-produced’ structure, whereby the offtake purchases all or a % of the renewable energy production and there is no volume or delivery obligation (U.S. Department of Energy, n.d.). We assume hydrogen producers procuring onshore wind PPAs will be eligible for the full IRA hydrogen production subsidy.

Wind purchase power agreement prices in the east coast are c. £24/MWh (U.S. Department of Energy, 2022) and while this price has been increasing slightly over the last few years due to supply chain pressures, it is projected to decline in future to £19.40/MWh due to increasing economies of scale, more competitive supply chains and further technological improvements (IRENA, 2019). The current capacity factor of onshore wind is 35% (U.S. Department of Energy, 2022) and will increase to 43.4% driven by improved wind turbine technologies, deployment of higher hub heights and longer blades with larger swept areas (IRENA, 2019). This enables an assumed electrolyser utilisation of 66.3% with a sleeved PPA agreement with a generator size of 1.3MW.

Electrolysis plant

Low-carbon hydrogen production requires electrolysis to convert low-carbon electricity and water into hydrogen and oxygen. There are currently several electrolyser technologies available. For this study, we have assumed the use of a 1GW alkaline electrolysis (AE) plant given it is currently and comparatively a more mature technology and lower cost. It is also currently the only technology that has been applied in commercial applications at sizes of more than 10MW. In Appendix 10.2 we considered the impact of using a proton exchange membrane (PEM) electrolyser on the levelized cost of production as a sensitivity.

The key considerations for this stage of the supply chain include the capital cost of the electrolysis plant, the indirect capital costs, and key operating parameters including electrolyser utilisation and efficiency of the system.

Capital costs

There is a wide range of capital costs for alkaline electrolysers quoted in literature, driven in part by the wide range of suppliers, locations of manufacture and the scope for the estimation of costs can be unspecified or inconsistent. For the purposes of this study, the overall capital cost used (see Section 8.1) is inclusive of the stack itself (the key component that separates hydrogen from oxygen) and indirect capital costs associated to power electronics, hydrogen purification and balance of plant. The range of alkaline electrolyser capital costs can be between c. £430/kW and £1,110/kW. We assume a CAPEX of £800/kW in 2023 (Oxford Institute for Energy Studies, 2022). This cost reflects the economies of scale of a 1GW plant, assuming manufacture in Europe.

Costs are expected to decline in future with maturing supply chains, increased economies of scale and technology improvements including increased stack lifetime, increased module and stack size, minimization of the use of scarce materials, and increased scale of production of electrolysers. The projected future costs of alkaline electrolysers could be between £150/kW and £600/kW (IEA, 2022c). We assume a conservative cost of £400/kW in 2045.

As noted, increased module and stack sizes can reduce the capital costs as large-scale hydrogen production benefits from economies of scale. The stack cannot be increased significantly due to challenges related to the manufacturing and possible mechanical instability issues of large-scale components (IRENA, 2020a). This means that the costs associated with the stack itself grows linearly as hydrogen production capacity increases. There are, however, opportunities for economies of scale particularly associated to reductions in shared costs such as balance of plant and development costs. Reductions in these shared costs, especially to the balance of plant could in turn have a large effect on cost savings as these costs contribute significantly to the overall CAPEX.

The largest economies of scale are around a 1GW module size after which the marginal cost decrease for increasing the capacity is much lower compared to smaller module sizes (IRENA, 2020a). This is because, it is anticipated that hydrogen production will be developed in multiple phases creating parallel production trains in a similar way to LNG and therefore accessing limited economies of scale. Figure 5 shows the LCOH reductions from scaling up from a 1MW facility to a 5GW facility in Scotland. To note, currently, the largest electrolyser installed is a 150MW facility in the Chinese region of Ningxia (Recharge, 2022), so reductions in LCOH due to economies of scale for system beyond this size are based on projections.

Figure 5 – Effect of economies of scale in electrolyser rating on LCOH

Operating parameters

In addition to capital costs, the operational parameters of the alkaline system can affect the levelized cost of production. The key operational parameters to consider include the efficiency of the asset, the stack life and electrolyser utilisation. These are presumed to improve in future due to technology improvements (Oxford Institute for Energy Studies, 2022).

Hydrogen transport via pipelines

Hydrogen can be transported in gaseous form via pipeline. Examples of hydrogen transport by pipeline are currently limited, however there are planned projects in multiple countries, including Scotland. We have assumed hydrogen will be transported via offshore subsea pipelines for Scotland, Norway and partly for Morocco. Similarly, most likely onshore pipelines will be used to transport hydrogen from France. Both onshore and offshore pipelines will be used for Morocco as subsea pipelines are required to transport hydrogen from Morocco to Spain. Pipelines from Chile and the USA have been excluded from the analysis due to the distances involved.

A compressor station is required to pressurise the gas, allowing the hydrogen to be transported long distances. Given how capital-intensive building or repurposing a pipeline is, it is typically only a cost-effective option for large scale hydrogen transport. The following sections provide more detail on the costs underpinning the cost of hydrogen transport by pipelines.

Pipeline inlet compression

To ensure hydrogen can be delivered to Rotterdam at an appropriate pressure, it must first be compressed at a large pipeline inlet compressor station.

The major driver of cost for the compressor station are the capital costs. The unit cost per megawatt for a large-scale station can range from £1.9m/MWe to £5.8m/Mwe (EU Hydrogen Backbone Initative, 2022). We assume the price of pipeline inlet compressor station will not change in future as the technology is already commercially mature resulting in limited opportunity for significant cost reductions.

The size of the pipeline inlet compressor station, and therefore the total CAPEX, will vary per case study country as the amount of hydrogen produced and distance it needs to travel will dictate the required size.

Pipelines

The components required for a hydrogen pipeline are essentially the same as for natural gas pipelines which are operated today. The cost estimates of hydrogen pipelines, as set out in European Hydrogen Backbone reports, are determined by gas transmission system operators experience in investing in and operating existing natural gas networks and initial hydrogen infrastructure pilot projects. The range of pipeline cost assumptions are based on assumed pipeline diameter, whether the pipeline is new or repurposed, whether the pipeline is offshore or onshore, and the pipeline utilisation. New, small diameter onshore pipelines (i.e. 20 inch) are cheapest at £1.2m/km to £1.6m/km whereas large diameter offshore pipelines can be c.£5m/km, depending on size (EU Hydrogen Backbone Initative, 2022). Finally, the cost of transporting hydrogen via a shared pipeline can be reduced on a levelised basis as pipeline utilisation is maximised. Shared pipelines are those with larger diameters that maximise utilisation by transporting hydrogen from multiple hydrogen producers. The full list of these cost assumptions can be found in Appendix 10.1.

Hydrogen transport by ship as ammonia

Figure 6 – Schematic of ammonia transport pathway

The low energy density of hydrogen can make it challenging to transport economically by ship. To overcome this, gaseous hydrogen may be converted to a more energy dense medium such as ammonia.

Today, ammonia is produced and transported globally in large quantities, especially for use as fertiliser. This means there is already a developed global supply chain for ammonia including production plants, storage tanks and transport vessels (although current production methods are carbon-intensive).

Ammonia production

We assume that ammonia will be produced using the Haber-Bosch process, which is the most common method for ammonia production at scale. The process requires: (1) hydrogen with buffer storage to enable a steady supply, (2) an air separator unit (ASU) to produce nitrogen and (3) ammonia synthesis plant where nitrogen reacts with hydrogen to form ammonia in the presence of a catalyst.

The key cost drivers of this process include the CAPEX of the buffer storage, ASU and ammonia synthesis plant.

Pressurised buffer storage CAPEX can vary depending on the storage pressure because lower pressures require larger storage tankers. CAPEX costs can range from £800-£1,300/kg of hydrogen (CSIRO, n.d.). For the purposes of this project, we assume more pressured buffer storage is required in case study countries where electrolysers are powered with intermittent renewables. We project less buffer storage in France and Norway where electrolyser utilisation rates are comparatively higher.

We assume the CAPEX cost of the ASU is c. £50,000/tons per day (tpd) and the cost of the ammonia synthesis plant is c. £285,000/tpd (Arup benchmark, n.d.). We assume the cost of the ASU remains constant in future due to the mature nature of the technology. However, we assume the ammonia synthesis plant CAPEX decreases in the future to £190,000/tpd (Arup benchmark, n.d.)as the existing global network of ammonia production grows to accommodate the future global hydrogen market.

Ammonia transport

Ammonia will be transported from a port at every case study country via a dedicated ammonia vessel. According to IEA, there are currently over 120 ports worldwide which can handle ammonia on a large scale (IEA, 2022c). Nonetheless it is projected that expanding the capacity of port infrastructure will be required to further enable the transport of large amounts of ammonia. Given this, we assume that the ports in all case study countries will require upgrades which involve CAPEX costs associated with new jetties, quay wall development and loading facilities.

Ammonia can be transported via different ship types, depending on how it is stored and today ammonia is typically transported in gas carriers designed for liquefied petroleum (LP). According to IEA, there are currently 200 gas tankers in operation across the world capable of transporting ammonia. They range in size with a carrying capacity of between 30,000 m³ and 80,000 m³, with the most recent orders having capacities of up to 87,000 m³ (IEA, 2023b).

The cost to ship ammonia will be dictated by the CAPEX of the vessel, OPEX, storage and cost of movement. According to BNEF, the total levelized cost of a 10,000 km trip of an ammonia vessel size with a carrying capacity of 23,000 tonnes is £1.37/kg H₂ (BloombergNEF, 2019b) .

Transporting ammonia in liquid form can result in reduction in volume as the temperature difference between the ammonia storage tanker and the ambient air temperature results in boil-off gas. The total daily energetic boil-off gas for ammonia is c.0.1%, which is less than other liquified energy carriers such as LNG, given ammonia has a comparatively higher boiling point (Al-Breiki & Bicer, 2020). This may have a limited effect on case study countries transporting ammonia short distances to Rotterdam, such as France, however the effect is more significant in countries further away, such as for Chile.

Ammonia cracking

Ammonia will be converted back to hydrogen at Rotterdam. We note, in some instances ammonia could be the end use product for, for example, fertiliser production. To decompose ammonia to hydrogen and nitrogen, an ammonia cracker is used. Crackers reverse the ammonia synthesis reaction via an endothermic process resulting in a cracked gas of hydrogen and nitrogen after which purified hydrogen can be obtained. Efficient processes for the recovery of hydrogen from ammonia require further development to be applied in commercial applications.

The key cost drivers of ammonia crackers include the CAPEX of the system and the energy required to recover the hydrogen, represented as a reconversion loss. According to a report by UK Government, the CAPEX of a cracker is £2.37 million/ tpd H₂ and we assume a recovery of 75% (UK Government, 2020). This study assumes that future technology improvements will increase efficiency and drive down energy consumption for ammonia cracking by 2045 (UK Government, 2020) .

Hydrogen transport by ship as compressed gas

Compressing hydrogen before loading it onto tanker ships analogous to those transporting compressed natural gas has potential to be a cost-effective mode of transport for lower volumes over shorter distances. The case for export via compressed hydrogen vessels from Chile and the USA have been excluded from the analysis due to infeasibility.

Currently, there is no global supply chain for shipping compressed hydrogen. However, smaller scale vessels are currently being developed and the first vessels could be operational as early as 2026 with larger scale vessels operational by 2030 (Provaris, 2022) . Although compressed hydrogen shipping is still nascent, it has been included as a pathway option due to its economic potential over shorter export distances, e.g. Scotland to Europe.

Compressed hydrogen will be transported via specialised vessels. Provaris, an Australian-based technology provider is planning to have vessels with carrying capacity of 26000 m³ by 2026 and 120,000 m³ by 2030 (Provaris, 2022). The smaller scale vessel will have a shipping range of up to 2,000 nautical miles and the larger vessel will have a range of up to 3,000 nautical miles making this pathway infeasible for countries further afield such as Chile and the USA.

The cost to ship compressed hydrogen will be dictated by the compression process, CAPEX of the vessel, OPEX, barge storage, port CAPEX and cost of movement. Provaris estimates an indicative levelised cost of transport (LCOT) of £3.75/kg for a single smaller vessel and £0.80/kg for the larger vessel (Provaris, 2022). Given the technology is still being developed there is significant uncertainty on costs.

Hydrogen production and transport costs

To determine if Scotland can produce green hydrogen at scale and export it cost competitively to the EU market, we have estimated the levelised cost of hydrogen production (LCOH) and transport to Rotterdam per case study country. We present this analysis for the hydrogen production pathway and three hydrogen transportation pathways:

• Production pathway
• Pathway 1 – Pipeline
• Pathway 2 – Shipping (Ammonia)
• Pathway 3 – Shipping (Compressed hydrogen)

For pathway 1, the LCOT has been evaluated based on the use of both dedicated and shared pipelines and new or repurposed pipelines. We have not presented the LCOT in 2045 for this pathway, as we assume no opportunity for cost reductions in future. For pathways 2 and 3, the LCOT has been evaluated for the years 2023 and 2045 to identify opportunities for cost reductions in future. We have compared the outputs of each pathway for each case study country to determine the most effective model for Scotland to produce and export hydrogen competitively in the EU market.

The key input assumptions for the levelized cost model are based on the cost review in section 7 of this report. All input assumptions and model methodology can be found the Appendix 10.1.

Large scale hydrogen production

Scotland analysis

Figure 7 shows the calculated LCOH in 2023 and 2045 for Scotland. The cost breakdown for the various production elements is also shown.

Figure 7 – Calculated LCOH for production of hydrogen in Scotland

The current cost to produce hydrogen in Scotland is estimated to be £6.58/kg H₂. The main drivers of this are the electricity input costs and the electrolyser capital costs, which account for 66% and 17% of the overall LCOH, respectively.

Figure 8 shows that the future cost to produce hydrogen in Scotland is expected to decline by 2045 to £3.43/kg H₂. This is driven by reduced electricity costs due to supply chain competition and scale up and reduced O&M, improved capacity factor of offshore wind generators driven by technological improvements and innovation and reduced electrolyser CAPEX due to maturing supply chains and technology improvements.

Figure 8 – Future production cost drivers for H₂ 2023 to 2045

Cost competitiveness

To understand Scotland’s potential as a large-scale exporter of hydrogen, the cost to produce in Scotland has been compared against the other case study countries in Figure 9.

Figure 9 – Calculated LCOH cost comparison

Today and in future, it will be cheaper to produce hydrogen in all case study countries compared to Scotland. This is due to the relatively high cost of offshore wind generated power compared to other technologies. In Norway and France, hydrogen producers benefit from low-cost electricity and high electrolyser utilisation, thanks to the high-capacity factor of grid electricity and nuclear power plants. There may be electricity constraints in France, as nuclear power is used to supply consumers rather than hydrogen producers. This means there could be limited ‘spare’ nuclear capacity available to supply producers. Building new nuclear plants are expensive and time consuming to construct. In Morocco, the complimentary coupling of onshore wind and solar generation also improves the electrolyser utilisation, but the additional cost of the second electricity sources increases its LCOH. Onshore wind costs in Chile and the USA are significantly lower than current offshore wind costs in Scotland. Electricity prices in the USA are particularly low as the Renewable Energy Production Tax Credit (PTC), a federal incentive that provides financial support for the development of renewable energy facilities, which has enabled and accelerated the onshore wind market. The hydrogen fuel tax credits via the IRA subsidy further reduces the cost of production in the USA.

Looking forward, Norway and France are expected to have limited overall cost reduction potential. Comparatively, we see a more significant cost reduction in Scotland, Chile, Morocco and the USA in future. LCOE and capacity factors for onshore/offshore wind and solar are projected to improve driven by reductions in CAPEX due to improved supply chains, reduction in O&M costs and innovation.

Overall, hydrogen production in Scotland is relatively more expensive compared to the other case study countries in the near and long term. The USA is estimated to be the most cost-effective large scale hydrogen producer with and without the IRA subsidy driven by the very low cost of onshore wind electricity. France and Norway are estimated to be relatively cost-effective large-scale hydrogen producers driven by cost-savings from the non-intermittent nature of their electricity source. However, by 2045, we expect Scotland’s hydrogen production cost competitiveness to significantly improve compared to the other case study countries due to efficiency advances and the cost reduction of offshore wind electricity.

Pathway 1: Pipelines

Pipeline transport pathway overview

Figure 10 – Schematic of pipeline transport pathway

The pipeline transport pathway considers an export model where, following production, the hydrogen is compressed and then transported to Rotterdam via a pipeline.

Scotland analysis

The calculated LCOT for transport via a pipeline from Scotland to Rotterdam is shown in Figure 11.

Figure 11 – Calculated LCOT for pipeline (pathway 1)

The cost to transport hydrogen from Scotland to Rotterdam is estimated to be £0.12– £3.16/kg H₂ depending on the pipeline model used. Transporting hydrogen via a new offshore pipeline is more expensive than via a repurposed pipeline because the work associated with repurposing is less extensive than building new infrastructure. Furthermore, transporting hydrogen via a shared large-scale pipeline is less expensive than via a dedicated smaller pipeline, as producers benefit from economies of scale. Figure 12 further illustrates that as the amount of hydrogen transported increases, LCOT declines significantly.

Figure 12 – Pipeline economies of scale

Cost competitiveness

To understand Scotland’s potential as a large-scale exporter of hydrogen, the cost to produce and transport via dedicated and shared pipelines from Scotland to Rotterdam has been compared against other case study countries in Figure 13 andFigure 14.

Figure 13 – Pathway 1 calculated LCOH and LCOT cost comparison for a dedicated pipeline

Variation in levelised transport costs across the case study countries are driven by distance and cost of pipeline material. Transporting hydrogen from France is cheapest given its proximity to Rotterdam and ability to use onshore pipelines which are less expensive than offshore pipelines. The cost to transport from Morocco is more expensive than the other case study countries given its further distance from Rotterdam and requirement for some offshore pipelines to transport to Spain. Norway is able to transport hydrogen more cost effectively than Scotland, despite the further distance from Rotterdam and same assumption that offshore pipelines are used. This is driven by the ability to transport a larger volume of hydrogen (based on a 1GW electrolyser) from Norway as producers benefit from higher electrolyser utilisation.

Figure 14 – Pathway 1 calculated LCOH and LCOT cost comparison for a shared pipeline

Our analysis shows that Scotland can transport hydrogen via pipeline cost competitively compared to the other case study countries. We have excluded Chile and the USA from this comparison as the distance to Rotterdam makes this transport option unfeasible. It is most economical for producers to transport hydrogen via large scale shared pipelines rather than smaller scale dedicated pipelines due to economies of scale. This indicates that a consolidated export strategy for Scotland to Europe could ensure that Scotland is able to remain cost competitive with competing countries. While France can export at a lower cost due to the use of onshore pipeline, routing and right of way could be challenging if dedicated pipeline corridors are not currently available.

Pathway 2: Ammonia Shipping

Ammonia shipping overview

Figure 15 – Schematic of ammonia shipping transport pathway

The ammonia shipping pathway reflects the supply chain for hydrogen exports in the form of ammonia. Pathway 2 considers the implications of converting hydrogen into ammonia, transporting it via ammonia carrier vessels and recovering hydrogen at Rotterdam.

Scotland analysis

Figure 16 shows the LCOT ranges for ammonia shipping in 2023 and 2045.

igure 16 – Calculated LCOH for ammonia shipping (pathway 2)

The costs to transport hydrogen via ammonia shipping from Scotland to Rotterdam is estimated to be £2.56/kg. The main drivers of the LCOT are the CAPEX-related costs of ammonia production, namely, the CAPEX costs of the ammonia plant, and the ammonia cracker which account for 38% and 34%, respectively of total LCOT in 2023.

The future cost to transport hydrogen via ammonia shipping from Scotland to Rotterdam is expected to decrease to £2.34/kg by 2045. This is due to assumed reduction in ammonia production capital costs and reduced reconversion losses from the ammonia cracker. This is driven by maturing supply chains and technological innovation as ammonia is increasingly used as a hydrogen derivative for transport.

As noted, a key cost driver to the LCOT for this pathway is the ammonia cracker CAPEX and OPEX. Excluding the ammonia cracker from the supply chain reduces the LCOT by c.41% (Figure 17). This suggests ammonia shipping becomes a more attractive transportation option where ammonia is being used as the end product, as opposed to re-converting to hydrogen.

Figure 17 – Pathway 2 pre-cracking cost comparison

Cost competitiveness

Figure 18 shows the LCOT of the ammonia shipping pathway for the case study countries, in 2023 and 2045.

Figure 18 – Pathway 2 LCOH production and transport cost comparison

The levelised cost to ship ammonia to Rotterdam today and in future are relatively aligned across the case study countries, with the cost to transport being slightly higher for Chile, Morocco and the USA. This is due to the longer distance the ammonia has to travel resulting in a higher cost of movement and increased effects of boil-off gas. As shown in Figure 18, hydrogen production costs contribute significantly to the total cost of export, both today and in future. This is why hydrogen producers in the USA, particularly those which benefit from the IRA subsidy, can export to the EU market via this pathway most competitively. Given this, Scotland should seek to reduce production costs to be able to transport via ammonia vessels competitively to the EU market.

Overall, the analysis shows that Scotland can transport hydrogen via ammonia shipping competitively compared to the other case study countries. Given how costly recovering hydrogen from ammonia is, this export model is most cost effective where ammonia is the end product.

Pathway 3: Shipping as compressed hydrogen

Shipping compressed hydrogen overview

Figure 19 – Schematic of compressed hydrogen shipping transport pathway

The compressed hydrogen shipping pathway reflects the supply chain for hydrogen exports in its compressed form. Pathway 3 considers the implications of compressing the produced hydrogen and transporting it via compressed hydrogen carrier vessels.

Scotland analysis

Figure 20 shows LCOH estimates for shipping compressed hydrogen from Scotland to Rotterdam.

Figure 20 – Calculated LCOH for compressed hydrogen shipping (pathway 3)

The costs to transport hydrogen via compressed shipping from Scotland to Rotterdam is estimated to be £1.88/kg and is expected to decrease to £0.32/kg by 2045. As compressed hydrogen shipping is in early-stage development, vessel sizes are relatively small at 26000m³. As a result, transportation costs are higher due to a larger number of trips required to transport GW scale hydrogen production. In future, as vessel sizes increase, transportation costs are projected to decline hence the reduction in LCOT by 2045.

Due to the constraint on shipping size, the feasibility of transporting via compressed hydrogen at the 1GW scale may need to be reviewed further. We also note, given the infancy of the technology, the costs are very uncertain.

Cost competitiveness

To understand Scotland’s potential as a large-scale exporter of hydrogen via compressed hydrogen vessels, the cost to transport from Scotland to Rotterdam has been compared against the other case study countries in Figure 21.

The analysis shows that countries in proximity to Rotterdam have an export advantage due to reduced transportation costs. Scotland, Norway, and France have significantly lower unit costs than Morocco, given the shorter shipping distances.

1.88

Figure 21 – Pathway 3 LCOH production and transport cost comparison

Countries with significant transport distances (Chile and Morocco) have disadvantages given that the small shipment loads of the compressed hydrogen vessels, which means that a high number of ships are required, subsequently increasing the costs. The high number of ships could also pose logistical problems that would need to be considered. Currently, it is cheaper for France to transport hydrogen via either dedicated or shared pipelines, however in future, it could be more cost efficient for France to export hydrogen via compressed vessels compared to pipeline transport.

Overall, the analysis shows that Scotland can transport hydrogen via compressed hydrogen shipping competitively compared to the other case study countries. Given the early stage of the technology, the feasibility of transporting GW-scale hydrogen production via compressed vessel must be explored further. Additionally, as the technology is not yet operational, projected costs are still uncertain.

Pathway comparison

Figure 22 presents the outputs of the Scotland base case levelized cost for each of the pathways that have been reviewed.

Figure 22 – Calculated LCOH and LCOT Scotland pathway comparison

The levelized cost analysis has shown that future cost reductions are expected across the pathways. It also illustrates that Scotland’s largest blocker to cost effective hydrogen exports is the current cost of production. Support from the Scottish and UK Governments in the form of subsidies and grants could help improve this.

Figure 23 – Most cost-effective transport pathway in 2023

Exporting large scale hydrogen production via shared pipelines is a cost-effective option due to economies of scale. For longer distance, converting hydrogen to ammonia and shipping via dedicated vessels is economical. Given how costly recovering hydrogen from ammonia is, this export model is most cost effective where ammonia is the end product. Shipping compressed hydrogen could be most competitive, particularly for smaller scale production and via shorter distances, however the technology still needs to be developed and proved Figure 23).

Figure 24 – Calculated LCOH pathway comparison by production scale

The cost of exporting via a pipeline is the only pathway that becomes more cost effective as production scales up (see Figure 24). Significant gains are expected up to 2GW after which cost reductions diminish. Both shipping pathways have a positive relationship between cost and scale. Large scale efficiencies tend to be limited for shipping as increased production requires a higher number of ships or frequent trips which affects costs.

The cost to ship ammonia is not influenced significantly by distance to the European market which makes this a cost-effective option for exporting countries further afield, such as Chile (see Figure 25). In contrast, there is a direct relationship between the cost to ship compressed hydrogen and distance making this export model most economical for shorter distances.

Figure 25 – Calculated LCOH ammonia and compressed hydrogen comparison by distance

Conclusions and recommendations

Figure 26 – Levelised cost of hydrogen production and transport (£/kg)

It is more costly to produce hydrogen in Scotland than in all other case study countries. This is because the cost of offshore wind generated power in Scotland is higher than the other low-carbon power technologies used. In other case study countries, such as France, which can produce hydrogen at a significantly lower cost, there could be low-carbon power constraints without additional investment in nuclear technology. In contrast, the Scottish Government has set ambition to invest in and scale up its onshore and offshore wind power to enable the growth of its green hydrogen sector.

Transporting hydrogen via pipeline is the most cost-effective option for shorter distances, large scale production and where the pipeline used is repurposed. Scotland should, therefore, evaluate the opportunity to repurpose existing pipeline infrastructure to improve its competitiveness in the EU hydrogen market. It should also develop a co-ordinated export strategy, bringing together multiple hydrogen producers to maximise utilisation of shared pipelines.

Exporting hydrogen via ammonia is a feasible option for countries further afield such as the USA and Chile. Additional costs associated with ammonia production and cracking back to hydrogen are significant. However, as distance from the EU increases, the costs associated with ammonia shipping movement do not increase significantly. As a result, this allows countries further away from the EU to participate in the hydrogen market. Given the additional costs associated to recovering hydrogen from ammonia, this export method becomes particularly cost effective where ammonia is the end product.

Transporting compressed hydrogen via vessels could be a promising export method for shorter distances and smaller scale production, driven by viable shipping range and size of the vessels. However, as the technology is not yet operational, the cost effectiveness and feasibility of this transport method will need to be further evidenced.

Scotland’s proximity to Rotterdam gives it a competitive advantage compared to countries further afield. This is because its proximity to the EU market enables it to export hydrogen via multiple transport pathways. In comparison, countries that are further away cannot export via pipeline or compressed shipping due to technical and cost feasibility issues. Secondly, Scotland’s proximity to the EU also allows it to export hydrogen via pipeline, which, today is the lowest cost export option.

To outcompete countries such as France and Norway, Scotland must reduce its production costs. However, even if the cost of production remains higher for Scotland relative to other European countries, Scotland will likely still be a market player, as France and Norway alone cannot meet EU hydrogen import targets.

Considering the evolving state of the hydrogen industry, it’s important to note that cost estimates for different aspects of production and transportation carry uncertainty. This variation introduces some level of uncertainty when assessing the competitiveness of hydrogen production and transportation in the EU market.

Government support could close the cost gap and enable Scotland to become a major competitor in the EU market. To do this, it should continue to support the scale up of offshore wind and hydrogen production to access economies of scale and enable the generation of surplus low carbon power for export. Scale up should target a reduction in low carbon electricity costs as well as electrolyser CAPEX. Secondly, it could provide subsidies to the sector. To enable Scotland to be competitive in the EU market today, a subsidy range of £60m to £500m per year (depending on the export method chosen) could be required. There is a particular need for UK government and Scottish government support for Scottish hydrogen producers to be able to out compete producers who benefit from USA IRA subsidy support and EU based support.

Appendices

Levelised cost model methodology and assumptions

The levelised cost model considers the cost of hydrogen production and transport in years 2023 and 2045. It considers the total costs (capital, operating, replacement CAPEX) of production and transport over the project life and divides it by the total volume of hydrogen produced and transported. Both the costs and volume of hydrogen produced and transported is discounted at a rate of 10% using the following formula:

𝐿𝐶𝑂𝐻 (£ 𝑘𝑔) = 𝑆𝑢𝑚 𝑜𝑓 𝑐𝑜𝑠𝑡𝑠 𝑜𝑣𝑒𝑟 𝑙𝑖𝑓𝑒𝑡𝑖𝑚𝑒 (£) × 𝑑𝑖𝑠𝑐𝑜𝑢𝑛𝑡 𝑟𝑎𝑡𝑒 (%) / 𝑆𝑢𝑚 𝑜𝑓 ℎ𝑦𝑑𝑟𝑜𝑔𝑒𝑛 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑 and transported 𝑜𝑣𝑒𝑟 𝑙𝑖𝑓𝑒𝑡𝑖𝑚𝑒 (𝑘𝑔) × 𝑑𝑖𝑠𝑜𝑢𝑛𝑡 𝑟𝑎𝑡𝑒 (%)

The sum of costs over the lifetime are based on the constant input assumptions outlined in Table 2. These input assumptions remain constant across all pathways. In addition to the constant input assumptions, there are input assumptions that vary between pathways and countries, such as the size of a pipeline inlet compressor, the supply chain requirements, etc. These supplement the constant input assumptions in order to determine the volume of costs for each part of the supply chain. The total discounted costs of production are then summed over the project life and divided by the total discounted volume of hydrogen produced.

The input assumptions are based on the literature review for each part of the supply chain (Section 7 of the report). We have used the trends that have been developed to identify the likely cost range for 2045. Table 2 highlights which sources have been used for which part of the supply chain per pathway.

The building blocks of the model are broken down into electricity generation, electrolyser (hydrogen production), compression, ammonia production (if applicable), transport, reconversion/ recompression (if applicable). For each part of the supply chain the inputs are used to determine an annual cost split between these categories:

• Capital costs of infrastructure
• Replacement costs of infrastructure
• Annual variable costs

Table 2 – Model input assumptions and sources

Sensitivities

Hydrogen Production Sensitivities

Table 3 provides a summary of the impacts on the production LCOH when key input parameters are changed. These results provide insights into the drivers the LCOH estimates.

Table 3 – Hydrogen production key sensitives

The results in Table 3 indicate the following:

• Increased efficiency in the production model yields a lower LCOH compared the base case, as it will reduce the electricity costs associated to power the electrolyser. Similarly, when lower CAPEX and OPEX cost assumptions are included, the LCOH declines. In particular, a decrease in CAPEX yields a significant drop in LCOH as it is major contributor to total costs.
• Over both years, the inclusion of lower electricity costs is expected to result in lower LCOH values. As electricity input costs are a major driver of production costs, minimising these costs will incur significant cost savings.
• In the near-term, the use of alkaline electrolysers is expected to offer cost-saving benefits due to their lower cost. However, by 2045, PEM electrolysers are expected to provide a lower LCOH due to cost reductions and longer stack life.

Ammonia Shipping Sensitivities

Table 4 illustrates the impact on LCOT for the Scotland base case when the shipping cost parameter is varied.

Table 4 – Pathway 2 transport distance sensitives

The analysis indicates that as transportation costs increase, the LCOT for ammonia shipping also increases. In practice, shipping costs may decline as ammonia transport is increasingly used to enable a global hydrogen market.

Compressed Hydrogen Shipping Sensitivities

Table 5 illustrates the impact on LCOH for the Scotland base case when the ship capacity is varied.

Table 5 – Pathway 3 production scale sensitivity

The analysis indicates that as overall ship capacity of compressed hydrogen vessels increase, the LCOH of this transport option decreases. As the compressed hydrogen industry continues to develop and transport vessels up-scale, further cost reductions could be realised.

Inflation Reduction Act (IRA) subsidy background

The Inflation Reduction Act (IRA) was passed by U.S. Congress in 2022 and provides a variety of incentives for clean energy projects in the USA. An estimated $369 billion will be spent under the Act to help address energy security and transition over the coming decade (International Council on Clean Transportation, 2023).

As part of the IRA, the 45V Hydrogen Production Tax Credit was introduced. It provides an income tax credit for every kilogram of qualified clean hydrogen produced. To qualify for the credit, hydrogen producers must meet the following criteria (Saber Equity, 2023):

• The production process must have a lifecycle greenhouse gas emissions rate of less than 4kg CO₂e/kg H2.
• The hydrogen must be produced in the US or a possession of the US.
• They hydrogen must be produced “in the ordinary course of a trade or business of the taxpayer”.
• The hydrogen must be produced for sale or use.
• An independent party must verify the “production and sale or use of such hydrogen”.

The tax credit is tiered based on the GHG emission intensity of the hydrogen produced. Hydrogen producers can earn up to $3 per kg of hydrogen produced for projects with a lifecycle greenhouse gas (GHG) emission intensity of less than 0.45kg CO₂e/kg H₂ (Center for Strategic & International Studies, 2023). In contrast, hydrogen projects which are more carbon intensive, such as steam reformation combined with CO₂ capture and sequestration, will qualify for a lower credit amount. Further guidance from the US Treasury Department in required for calculation of emissions intensity levels of electrolysis-based hydrogen (Center for Strategic & International Studies, 2023).

The tax credit will expire in 2032 so projects which become operational in 2023 can benefit from the full 10 years of the credit, while plants which become operational later will receive progressively less (International Council on Clean Transportation, 2023). Additionally, the 45V Hydrogen Tax Credit is also “direct pay” for the first five years of operation. This allows clean hydrogen producers to claim a tax refund equal in value to their tax credits for five years.

The US Government also introduced the 45V Renewable Electricity Production Tax Credit. This offers renewable electricity producers a tax credit up to 2.6 cents per KWh of energy produced (The International Council on Clean Transportation, 2023). The renewable energy credit works in a similar set up to the hydrogen production credit. Projected figures suggest the IRA tax credit for renewable electricity and clean hydrogen can reduce the cost of green hydrogen production by almost 50% (The International Council on Clean Transportation, 2023).

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If you require the report in an alternative format such as a Word document, please contact info@climatexchange.org.uk or 0131 651 4783.

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© Published by Ove Arup & Partners Ltd, 2023 on behalf of ClimateXChange. All rights reserved.

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DOI: http://dx.doi.org/10.7488/era/3892

Executive summary

Aims

The Scottish Government’s draft Energy Strategy and Just Transition Plan emphasises the importance of local and community energy projects for supporting Scotland’s net zero and just transition ambitions.

This study aimed to understand how those projects can help deliver against these ambitions within devolved powers. The research explored developments in local and community energy and assessed key innovations, opportunities and barriers, and how to leverage those projects to support Scotland’s National Just Transition Outcomes (NJTOs).

The methodology included a literature review, interviews with citizens, local and community energy practitioners and other key energy and just transition stakeholders (including just transition experts and researchers; local authorities; fuel poverty and third sector charities; energy finance and investment stakeholders; energy developers and networks; and those working in local energy innovation initiatives such as the Prospering from the Energy Revolution programme and a deliberative ‘People’s Panel’ with Scottish citizens.

Findings

• Looking at evidence from Scotland and across the UK, we have found that local and community energy can directly contribute to all eight of Scotland’s National Just Transition Outcomes.
• There are key barriers to delivering against these outcomes across sectors: limited resources to build capacity for local and community energy projects in underserved areas; challenges around skills and project delivery processes particularly within local authorities; justice and equity issues within projects themselves; and lack of appropriate finance and business models.

Recommendations

We set out six overarching recommendations to help increase the contribution of the local and community energy sectors to Scotland’s Just Transition, and provide a set of 19 evidence-based actions to increase local and community energy as the Scottish Government develops the final version of its flagship Energy Strategy and Just Transition Plan.

The recommendations are designed for Scottish Government policymakers and other key partners, including local government, delivery bodies, the energy industry, communities and wider stakeholders working across energy, heat in buildings, transport, land use and planning, economic development, communities and fuel poverty. There are also wider lessons for those developing local and community energy approaches across the UK and Europe with a just transition in mind.

• Increase community capacity and outreach, including resource for and awareness of the local and community energy sectors to support capacity-building, effective project development and outreach, particularly in typically excluded communities.
• Support the development of new local and community energy models, including the skills, resource and networks required for communities and local authorities to fully embrace them.
• Enhance community ownership of energy and governance of projects, ensuring these are accessible, accountable and transparent, with proactive inclusion of marginalised and excluded groups.
• Increase participation and engagement, ensuring that all groups and communities have a fair opportunity to engage with local and community energy projects, to help participate in governance and decision making, and shape projects from the beginning.
• Develop sustainable finance, funding and investment models that ensure those who can’t afford to pay are not excluded and that maximum value is retained locally, with just transition outcomes explicitly prioritised.
• Open up benefits of local and community energy projects to as wide a range of people and places as possible, from decarbonisation and bill savings, to skills, through to supply chains.

Abbreviations table

Introduction

Community energy in Scotland

For over a decade, Scotland has strived to lead the way in local and community energy, with a Scottish Government target to reach two gigawatts of installed local and community-owned capacity by 2030 (Scottish Government, 2021a).

While aspects of energy policy and regulation in the UK are reserved, limiting the work that Scottish Government can do to fully enable local and community energy in Scotland, the Scottish Government has fostered a favourable policy environment for this sector. This is mainly through providing funding via the Community and Renewables Energy Scheme (CARES) to support the development and delivery of local and community energy projects. CARES has supported over 800 projects and 1000 organisations with over £61 million in funding (Scottish Government 2023b).

More recently, the Scottish Government has supported local authorities to deliver their own Local Heat and Energy Efficiency Strategies, which will set the foundation for more local energy systems and initiatives (2022a). Alongside this, there has been the announcement of the Onshore Wind Sector Deal (Scottish Government 2023c) – a shared commitment between the Scottish Government and industry to deliver against Scotland’s ambition of 20 gigawatts of onshore wind by 2030, in a way that aligns with the principles of a just transition.

Within this positive context, there are clear opportunities to further accelerate Scotland’s good work on local and community energy so far. Local and community energy, such as community-owned wind and solar, or district heat projects led by local authorities, can provide substantial social, economic and environmental benefits to people, places and a range of other stakeholders.

The benefits of local and community energy include: new revenue streams for local areas; new business and investment opportunities; reduced emissions; climate education and outreach; climate adaptation and resilience; improved capacity in local communities; new skills and job creation; and reduced fuel poverty (Ford et al., 2019; Gooding et al., 2020; PwC, 2022). Community and local energy also provides an opportunity to make Scotland’s net zero transition more local, democratic and inclusive, with energy projects and solutions better tailored to local needs.

These diverse benefits mean that local and community energy is well placed to contribute to achieving against Scotland’s eight National Just Transition Outcomes (NJTO) (Box 1). The National Just Transition Outcomes are a set of goals designed by Scottish Government, informed by the Just Transition Commission (2023), to help mitigate the risks of climate action and unlock the opportunities that a just transition presents across sectors and policy areas (Scottish Government 2022b). Within the context of the finalisation of the Energy Strategy and Just Transition Plan (ESJTP) and aligned policies such as the Heat in Buildings Strategy, local and community energy could thus have a significant role to play.

Methodology

In this report, we outline how to develop the local and community energy sector in Scotland in such a way that it delivers against Scotland’s NJTOs. To do so, we conducted a three-step research approach (these are detailed in appendices A and B). First, we conducted an extensive review of academic, policy and project literature and case studies. This allowed us to understand the most recent thinking and developments in the local and community energy space, and identify key just transition trends and issues.

Second, we interviewed 22 expert stakeholders. These included: community energy organisations; just transition experts and researchers; local authorities; fuel poverty and third sector charities; energy finance and investment; energy developers and networks; and those working in local energy innovation initiatives such as the Prospering from the Energy Revolution programme (UKRI, 2023). These stakeholders were chosen to give a breadth of perspectives on leveraging local and community energy for just transition outcomes beyond energy specialists alone, and to understand any key points of conflict between sectors and stakeholders.

Third, we conducted a “People’s Panel” with 22 Scottish citizens, most of whom were from lower income areas of the country. This helped to understand the opportunities and barriers people faced to participating in local and community energy projects, and how these sectors could best be opened up to improve buy-in from communities and provide diverse NJTO benefits to people and places.

There was higher representation from both citizens and local and community energy practitioners than renewable energy developers and businesses in this process. This was deliberate, because citizens and local and community organisations, particularly those working on just transition issues, have not always been involved in such discussions, yet can provide crucial insights on how to best open up local and community energy for a wider range of just transition outcomes. This means that our findings in turn reflect the perspective of those stakeholders more. Further engagement with energy developers and businesses would help make recommendations more robust.

What is local and community energy?

The Local Energy Policy Statement (Scottish Government 2021a) outlines three main categories of community and local energy projects (Table 1).

Across these categories, 908 megawatts of Scotland’s 2 gigawatt target for local and community energy has been delivered. This includes a mix of community energy projects, local authority energy projects, social and housing association developments, public sector investments, as well as initiatives in businesses and on farms and estates.

Table 1. Three categories of local and community energy per the Local Energy Policy Statement (2021)

Although they share a number of key features, community energy, local energy and local energy systems do have distinct differences.

Community energy is typically characterised by grassroots action, where a community (either a community of place or of shared interest) comes together to design, implement, and manage a renewable energy asset or project. This might be a community energy generation project, such as a wind turbine or solar panels, or a heat, retrofit or transport scheme. These are often driven by a shared mission to deliver environmental, social and economic value for a specific place, with democratic input and governance (Brummer 2018; Creamer et al. 2020; Stewart 2021; Hanke et al. 2021).

Local energy and local energy systems are more diverse. They tend to have less of a primary focus on communities, and can be delivered though multi-stakeholder collaborations, often led by local authorities or the public sector, or through public-private collaborations (Ford et al., 2019; UKRI and Regen, 2022). They are less like the grassroots model seen in community energy and more akin to local authority-led or partnership approaches (Devine-Wright, 2019).

Value against Scotland’s NJTOs

Table 2. Value from local and community energy across National Just Transition Outcomes

Different models of local and community energy will have different implications for Scotland’s NJTOs. Community-owned energy generation, for instance, is particularly strong on citizens, communities and place, by bringing people together to deliver projects and generating new revenues for local economic development. Community-owned energy generation projects also tend to be strongly motivated by climate and environmental outcomes (Community Energy Scotland, 2022; Community Energy England, 2022; Stewart, 2021).

Local energy and local energy systems tend to focus more on delivering economic value, such as a larger-scale return on investment for stakeholders, and new jobs and skills in retrofit, system installation, maintenance, etc. (Ford et al., 2019; Gooding et al., 2020; PwC 2022).

1. Table 2 above outlines the high-level opportunity of local and community energy approaches for Scotland’s NJTOs. Table 3 illustrates the value that each main category has had so far for each of the NJTOs (Low = low value for NJTO) based on our review of empirical research and engagement with local and community energy stakeholders. A detailed qualitative analysis of these relationships across community energy, local energy, and local energy systems can be found in Appendix C

Appendix C: Local and community energy just transition outcome impacts.

Table 3. Illustration of how priorities for local and community energy vary against the eight NJTOs

Table 3 and Appendix C highlight important qualitative differences in how community energy, local energy, and local energy systems deliver value against different NJTOs. However, projects can vary substantially within these broad categories. This also leads to variations in impact on NJTOs.

For example, a local energy project that focuses on decarbonising council buildings, such as leisure centres or commercial properties, will contribute less to NJTOs 1, 3 and 8 than one that supports council housing tenants to decarbonise their homes. A community energy project which uses generation assets to provide new revenues to deliver energy advice and local environmental protection will also contribute more towards NJTOs 1, 2, 6 and 7 than wind turbines installed on a farm or estate.

As such, supporting a balance of different types of projects across regions and areas can help contribute to all of Scotland’s just transition outcomes, allowing projects to meet local need. Projects themselves can also be supported to become fairer and more inclusive, which we deal with later in this report.

Just transition: processes and outcomes

Outcomes are only one part of the picture. As the Scottish Government (2021b) highlights, a just transition is also about process. This means that projects should be designed to enable people to take part in decision-making around the project. Who owns, gets a say, participates in, pays for and benefits from local and community energy projects all have implications for how just projects are considered to be by communities.

From our review of academic evidence and stakeholder engagement, we identified four key dimensions along which projects vary, with implications for how just they are considered to be. These dimensions are applicable to all types of local and community energy and should be considered together (Table 4).

Table 4: Key dimensions for ‘just’ local and community energy projects

From this analysis, leveraging local and community energy for a just transition means: expanding local and community energy across regions as a whole; and creating the right policy and delivery environment to enable projects to be more just in their processes and outcomes.

In the next section, we provide a high-level overview of key models and developments in each sector. The remainder of the report then provides recommendations for Scottish and Local Government policymakers and delivery bodies working across energy, heat in buildings, transport, land use and planning, economics, local government, communities and fuel poverty.

While this report does not represent Scottish Government policy, it makes recommendations to inform the role of local and community energy in key national policies, including the forthcoming final ESJTP as well as delivery of adjacent strategies such as implementation of Local Heat and Energy Efficiency Strategies (LHEES) and wider Heat in Buildings Strategy, Community Wealth Building, and Local Development Plans under National Planning Framework 4.

Community energy

Community energy has flourished in Scotland during the last decade, with 101 megawatts of community-owned generation capacity reported to be in operation or in-development as of December 2022 (Scottish Energy Statistics Hub 2023). Many other projects are also in motion e.g. decarbonisation of heat and transport. This is illustrated in the illustration opposite which shows a community using renewable energy.

The Community and Renewable Energy Scheme (CARES), administered by Local Energy Scotland, has provided over £60 million development and capital support. Community energy has thus enjoyed a favourable devolved policy ecosystem. Key developments in the community energy sector are as follows:

‘Traditional’ community ownership and community shared ownership generation projects; Rooftop solar and ‘traditional’ wind projects on community land and buildings; many-to-many power purchase agreements with public sector and commercial offtakers; exploring opportunities to link with community-owned land and housing

Community-owned electric vehicle charging, sometimes paired with car sharing.

Generation and supply

Heat and energy efficiency

Transport

Decarbonisation of community buildings using heat pumps and energy efficiency, providing lower bills to help keep social spaces open and warm hubs over winter; exploring potential for district heat networks and bulk purchase of heat pumps; community-led efficiency and retrofit programmes.

Just transition outcome contribution: citizens, communities and place; climate adaptation and resilience; environmental protection and restoration; decarbonisation and efficiencies; equality and human rights.

Key developments

Generation and supply

Since the winding down of the UK Government Feed-In Tariff – replaced by the less lucrative Smart Export Guarantee – community energy generation in Scotland and the UK has been forced to rely on other models.

This has often taken the form of Power Purchase Agreements (PPAs) with local stakeholders such as councils, colleges, businesses and hospitals – or directly with utility companies (Community Energy England 2022; Crown Commercial Services 2020).

PPA’s are arrangements where either utilities or local bodies can purchase energy from community-owned generation for a fixed term at a fixed price. In the case of Edinburgh Solar Cooperative, for instance, the Cooperative installed solar panels on a number of City of Edinburgh Council buildings (City of Edinburgh Council 2014). The solar panels provide some of the electricity generated to the buildings on which they are installed at a reduced rate compared to typical market tariffs. This is facilitated by a Power Purchase Agreement.

The traditional model of selling energy to the national grid is also still used, particularly with larger-scale wind and solar projects using local or community land which are better-placed to make a return than smaller installations (Community Energy England, Scotland, Wales 2022). This in turn provides community benefit funding which can be used to deliver against just transition outcomes. In particular, state of the sector reports show that this has been used for:

• Building capacity in communities through social gathering, engagement, and outreach
• Delivering energy advice and advocacy and helping people in fuel poverty
• Promoting climate education through hosting workshops, events and cafes
• Developing climate adaptation measures, such as investing in green spaces or nature restoration

Heat and energy efficiency

Decarbonisation of community buildings has been the predominant form of community heat progress in Scotland (Local Energy Scotland, 2023a). This includes installing efficiency measures and heat pumps to reduce bills for public and shared use buildings e.g. community centres. This can help reduce costs for running community spaces, provide sustainable and warm social centres for local residents and support education around new technologies or initiatives.

More ambitious heat projects are being explored, such as bulk purchase of heat pumps for local homes and district heat networks, for instance by Local Energy Scotland’s CARES-funded Community Heat Development Programme (2023b).

However, these remain expensive and complex undertakings for community organisations at present. The legal, financial and technical expertise required is significant, meaning organisations that rely on volunteers and limited resource struggle to deliver them effectively. Within Local Heat and Energy Efficiency Strategies (LHEES), there is scope for communities to work with local authorities to identify opportunities and deliver such projects in partnership. Projects elsewhere in the UK, such as Swaffham Prior, show how community heat and community energy generation can work together in partnership with local authorities and the private sector to deliver such projects successfully (Cambridgeshire Country Council, 2023).

There have also been advances in community approaches to energy efficiency and retrofit. Community organisations such as the Carbon Coop in Manchester (People Powered Retrofit, 2021), Loco Home Retrofit in Glasgow (2023), and the Heat Project Blairgowrie (2023) have been supporting homeowners to install energy efficiency measures along with low carbon technologies such as heat pumps and solar panels.

This provides new opportunities to support people in often disadvantaged or excluded communities to decarbonise, and jobs, skills and education opportunities for local businesses and tradespeople.

Transport

Local and community transport projects have broadly taken the form of electric vehicle (EV) charging points, either supplied by local generation assets as funded by Brighton Energy Coop’s Community Solar Accelerator Grant scheme (2021), or as assets themselves, creating revenue through subscription and pay-as-you-go tariffs as with the Charge My Street initiative (2023).

EV charging is seen as a relatively low-risk project by community energy stakeholders spoken to as part of this research. However, installing chargers does rely on locational factors such as the availability of network capacity and parking facilities, as well as people using the chargers themselves to generate revenue (typically more affluent groups – see Hopkins et al., 2023).

Local energy

Local energy has experienced considerable growth in recent years, and has become increasingly salient in energy policy thinking.

Recent research estimates that 1 in 5 UK local authorities now have some form of local energy project, which can take various forms across a range of scales (Arvanitopoulos et al. 2022).

Similar to community energy, local energy tends to encompass generation and supply projects,
heat and energy efficiency schemes, and transport solutions. This is illustrated in the image opposite which shows a variety of buildings being served by the same energy source in a community. Local energy includes:

Local authorities delivering e-bikes, EV charging etc., EV charging in social and housing and associations.

Local authorities delivering Community Wealth Building-style (CWB) projects (North Ayrshire) and solar in council housing; solar and storage in social/housing associations; commercial and business properties installing own technologies.

Generation and supply

Heat and energy efficiency

Transport

Local authority and commercial district heat networks (Edinburgh Vattenfall) and heat pumps, including in leisure centres; place-based energy efficiency approaches; commercial and business properties installing own technologies.

Just transition outcome contribution: citizens, communities and place; jobs, skills and education; fair distribution of costs and benefits; decarbonisation and efficiencies; equality and human rights (when targeted at lower income households).

Key developments

Generation and supply

At a local level, local authorities, housing associations and social housing providers are increasingly decarbonising their electricity supply (UKRI and Regen 2022). This has mostly taken the form of installing solar panels (often with battery storage) in their housing stock to reduce bills for tenants, and in a wider decarbonisation of public, commercial and industrial buildings.

Often working with low income social housing tenants directly, this has created value for decarbonisation and efficiencies, and had a further impact on equality and human rights through tackling fuel poverty. Compared to community energy, local authorities have direct access to their own housing stock, making installation of measures for lower income groups more straightforward. Delivering measures is still challenging for the private rented or owner-occupier sectors, however.

Some local authorities such as North Ayrshire Council (2020) have been leading the way to deliver just transition value, through advancing plans for using council-owned energy generation to fund work addressing fuel poverty, as well as energy efficiency and Community Wealth Building programmes (Figure 1). In addition to contributions to the just energy transition, this also has the potential to deliver jobs, skills and education, as well as provide a strong boost to citizens, communities and place through enabling local value generation, retention, and more open decision making.

Revenues reinvested in local economy, eg:

• Tackling fuel poverty
• New jobs and skills
• Local business and economic development
• Other energy projects
• As per local need

Money generated predominantly from exporting to the grid, or supplying energy to local public and commercial buildings.

Local authority sources investment to develop municipal electricity generation assets, such as a wind or solar farm (or both).

Figure 1. Local authority-led generation for community wealth building example

Heat and energy efficiency

Alongside generation, the same organisations have been installing heat pumps, often in housing stock but more often to serve larger commercial and public sector buildings. Local authorities have been leading on place-based energy efficiency schemes, with LHEES underway and due to be delivered in late 2023.

As with community energy, these carry benefits for decarbonisation and efficiencies, taking a more tailored, place-based approach to reducing housing stock emissions, while supporting lower income and excluded groups to transition to low carbon technologies (Regen 2022).

Several local authorities, such as Midlothian Council (2022) and Stirling (FES, 2023), are also delivering larger heat network projects to serve a mix of domestic, industrial and commercial properties. This can create wider business and economy opportunities for investors and developers, generating new work and business for local places.

Transport

Beyond coordinating public transport and decarbonising their own transport fleets, local energy transport initiatives today typically take the form of e-bike services led by local authorities, charging in social and housing association properties, or public electric vehicle charging and car clubs. The Plugged-in Communities Scotland Fund (Energy Savings Trust, 2023), for instance, provides funding for community transport organisations – often housing associations – to deliver car clubs and charging for their tenants and the wider community. In terms of value for just transition outcomes, this can support decarbonisation and efficiencies through encouraging more active and public travel, although can be restrictive for those outside of city centres or without driving licenses.

Local energy systems

Often known as ‘integrated’ or ‘smart’ local energy systems, local energy systems have become increasingly prominent in the local energy landscape.

Spearheaded largely by the Prospering from the Energy Revolution programme (2023), local energy systems bring together a combination of generation, storage, heat, transport and demand at a local level. This is done using physical infrastructure, digital platforms and local energy markets.

These have generally taken trial form at a town or city level and are usually led by local authorities, in conjunction with a wide consortium including communities, academia, businesses and developers. This is illustrated in an image below which shows how solar, wind and heat pump energy sources can be integrated into community energy supplies.

This has been the case in the landmark Bristol City Leap project, for instance, delivered in partnership with Bristol City Council, industrial partners Amaresco, community organisations, and developers Vattenfall (Bristol City Leap, 2022). The project will install and operate new solar, wind, heat pumps and networks, EV charging and energy efficiency measures in homes and businesses across the city to help meet their 2030 climate targets.

’Integrated’ or ’smart’ local energy systems, largely at innovation stage, now moving more into business-as-usual. Bringing together a combination of electricity, heat, transport, storage and demand at a local level, using smart technologies and digital platforms.

Just transition outcome contribution: jobs, skills and education; business and economy; decarbonisation and efficiencies.

Key developments

Still in their early stages, integrated local energy systems provide a range of opportunities against each of Scotland’s NJTOs, particularly on jobs, skills and education and business and economy. They also provide opportunities for installers, energy businesses and developers, data scientists, engineers and project managers (UKRI and Regen 2022; Chitchyan and Bird 2022).

Within integrated local energy systems, there is also scope to build community benefit and ownership of generation or district heat assets. As part of the current Bristol City LEAP project, a £1.5 million Community Energy Fund has been included as part of the deal to help communities develop their own local energy solutions and hold a stake in the wider initiative (in addition to the LEAP project creating an estimated 1,000 jobs across planning, design, data, installation and retrofit, and deliver £2.8 million to local community projects).

However, these systems can be big undertakings, requiring significant public and private finance to deliver. Given their novelty, they can be seen as risky, and some policy and regulatory issues still remain at UK level (see Section 1.128).

Local energy planning

Local energy planning is becoming a key function of local authorities in Scotland and across the UK. In Scotland, this has at least partly been driven by Scottish Government requiring Councils to develop their Local Heat and Energy Efficiency Strategies (LHEES), setting out the long-term plan for decarbonising heat in buildings and improving their energy efficiency across an entire local authority area (Scottish Government, 2022a).

Some local authorities, such as Dundee City Council with their Regional Energy System Optimisation Planning (RESOP) project (Scottish and Southern Electricity Networks, 2022), have voluntarily broadened out into local area energy planning (LAEP) to include generation, transport and storage as well as heat and efficiency. Stirling and Clackmannanshire have also delivered a Regional Energy Masterplan which covers a similar scope (Engage Stirling, 2023).

Distribution network operators play a key part in this, supporting local stakeholders to develop plans for network investment and system design, with an increased focus on local planning and delivery under their new funding obligations. Ofgem’s Review of Local Energy Institutions and Governance, and Regional System Planning consultations are now exploring what is likely to be a prominent future role for local and community energy in the energy system (Ofgem 2023).

This new prominence of local energy planning can support the development of local energy projects and systems, in close tandem with communities and citizens. It can also allow local authorities to better plan their decarbonisation efforts, and begin to mobilise necessary local skills and finance.

Outside of LHEES, there is no set standard for the level of energy planning local authorities or stakeholders are currently expected to deliver – in Scotland or across the UK. The level of skills and resource that local authorities have in-house can also vary substantially, making it difficult to deliver more ambitious projects consistently across the country.

Recommendations

It is clear that different forms of local and community energy can make a significant contribution to Scotland’s eight National Just Transition Outcomes. New developments, particularly in community heat and efficiency, local energy systems and local energy planning, also present new opportunities.

However, key barriers remain to realising these at scale. Local or community-owned energy is also not automatically more ‘just’ than larger-scale developments. Who owns, governs, participates in, funds and benefits from local and community energy projects will impact how ‘just’ they ultimately are. Leveraging local and community energy for just transition outcomes thus means:

• Better enabling the delivery of more projects in more places
• Making sure projects embed just transition principles throughout

To support this, we have developed the following six key overarching recommendations for Scottish policymakers and delivery bodies, energy industries, communities and wider stakeholders, which can help unlock local and community energy going forward:

• Increase community capacity and outreach: Increase resource for and awareness of local and community energy, to support capacity-building and effective project engagement – particularly in underserved communities.
• Support delivery and innovation: Support the development of new local and community energy models, including the skills and networks required for community and local authorities to fully embrace them.
• Enhance ownership and governance: Expand community and local ownership of energy, ensuring that ownership and governance of projects are accessible, accountable and transparent, with proactive inclusion of marginalised or excluded groups.
• Increase participation and engagement: Ensure that all groups and communities can realistically engage with local and community energy projects, to participate in governance and decision making, and shape ideas from the beginning.
• Develop finance, funding and investment: Develop sustainable finance and business models that ensure those who can’t afford to pay are not excluded from participation or benefit and that maximum value is retained locally, with just transition outcomes explicitly prioritised.
• Open up benefits to beneficiaries: Open the benefits of local and community energy projects to as wide a range of people and places as possible, including everything from household decarbonisation and bill savings, to skills and supply chains.

These recommendations are applicable across community energy, local energy, and local energy systems. The following sections give specific actions to realise these, and explain how these suggested actions are supported by research.

Increase community capacity and outreach

Recommendation 1: Increase resource for and awareness of local and community energy, to support capacity-building and effective project engagement – particularly in underserved communities.

Community energy projects often aim to target lower income areas, to challenge fuel poverty and deliver benefits to often disadvantaged places (Stewart 2021; Community Energy Scotland 2022; Community Energy England 2022; Cairns et al 2023). However, projects in lower income areas can still be few and far between. Community energy literature highlights that in Scotland, the UK and more broadly, areas of higher deprivation and places without strong existing development associations or community energy groups can struggle to develop and participate in community energy projects (Hanke et al 2021; Brummer 2018).

Although Scotland has fostered a favourable policy environment for community energy, community energy organisations and third sector stakeholders recognise this issue, and note that there remains a lack of consistent capacity and resource within communities to deliver or participate in projects at a wider scale.

This makes it challenging for more communities to participate in community energy, local energy developments, or to pursue shared ownership arrangements. Expanding resource for capacity building and raising awareness for local and community energy would help develop National Just Transition Outcomes in these areas.

Action: Run a large-scale awareness-raising campaign around community energy, the potential benefits it brings, and entry points for communities

Our research with community energy stakeholders, third sector organisations working directly with the public, and citizens in our People’s Panel has shown that awareness of community energy among the general public remains low. Of the 22 participants in our People’s Panel, only one had heard of community energy prior to this engagement. Community energy groups and wider community organisations also reported encountering a lack of awareness when they engage in new areas.

To deliver more community energy projects for just transition outcomes, there is a need to improve awareness of the sector, and its possibilities, across the board.

Action: Support the hiring of local and community energy development officers at a more consistent local level

Research from Slee (2020) highlights that the success of community energy projects largely depends on there being skilled and knowledgeable actors with local as well as business and technical knowledge in a particular community. At present, Local Energy Scotland have eight regional development officers. However, this is not seen by local, community or energy innovation stakeholders as granular enough to build meaningful local capacity in diverse communities across the country.

Local and community energy stakeholders (again highlighted by Slee, 2020) likewise cited that it is often the same organisations, groups and development trusts which apply for funding because they know the process and have some capacity and expertise already, with limited applications from new groups or areas.

To better unlock new projects in new areas for just transition outcomes, skilled development officers employed at a more granular spatial scale, such as local authority for instance, could allow for more targeted local development and encourage better links between local authorities and communities.

Action: Expand CARES funding to provide a wider range of support, such as capacity building and more substantial core staff resource for community energy organisations

The CARES programme, managed by Local Energy Scotland, successfully supports community energy projects in Scotland with loans, grants, and procedural assistance. To date, it has been one of the first ports-of-call for community energy. However, local and community energy stakeholders called for two key improvements to be made to the CARES programme.

Firstly, local and community energy stakeholders argue that CARES may benefit from being more flexible in its funding criteria across calls and programmes. Organisations involved in our research noted there is not enough funding available to build capacity or pay community energy volunteers for their time without there first being a project in place, which makes it difficult to develop sustainable projects, particularly in new areas, or retain people to drive projects forward. Enabling more funding for capacity building and core community energy staff in particular would allow existing projects to expand, explore new models and options and help more projects to come to fruition in new and different places.

Action: Develop a roadmap of the support that CARES provides throughout the project process to make it clearer to local and community organisations

Second, our research participants commented that the support that CARES can offer to community organisations, particularly once a project has been established, is not always clear. Signposting to the website is useful but once there, community organisations note that specifics on the support available at different project stages is lacking in detail. An accessible, easy-to-navigate roadmap outlining precisely the support available at each stage of different types of project (wind, solar, hydro, generation, heat, transport, etc.) would help demystify this for prospective new community energy organisations.

Support delivery and innovation

Recommendation 2: Support the development of new local and community energy models, including the skills and networks required for community and local authorities to fully embrace them.

Innovation has been a cornerstone for both local and community energy. Community energy has often innovated by necessity, while local energy systems such as those trialled under the Prospering from the Energy Revolution programme have pushed innovation at the nexus of technology, business models and regulation in recent years. These innovations present new opportunities to deliver against just transition outcomes which the Scottish Government can more effectively support.

Action: Build on Heat in Buildings and Net Zero Skills Strategies to include training around local energy systems for local authorities and interested industry stakeholders

A wealth of evidence already exists on the opportunity, barriers and operationalisation of local energy systems across the UK (Regen 2023; Energy Systems Catapult 2022).

A key challenge that remains relates to the lack of skills within local authorities to spearhead local energy system developments (Chitchyan and Bird, 2022). While LHEES has improved local energy understanding, local authority stakeholders note that there is still often a lack of skills (and resource) for local energy projects in general. These skills gaps include creating appropriate partnerships, engaging the community, knowledge-sharing and developing successful business models and governance structures within current regulatory frameworks.

Developing flexible, modular training with bodies such as Skills Development Scotland or the Improvement Service, or learning from knowledge-sharing initiatives such as the GreenSCIES local energy Centre for Excellence (UKRI and Regen 2022) could help to overcome this issue, and help contribute to the capacity within local authorities to take local energy projects forward.

Action: Work with prospective public and commercial sector stakeholders to promote community energy as an option for their energy supply

In the absence of a steady revenue stream for community energy generation projects, some are increasingly exploring Power Purchase Agreements (PPAs) with public and commercial organisations.

These PPAs can help to provide revenues through which community energy can deliver across all NJTOs to some degree (depending on local need and ambition). Bringing several PPAs together (i.e. selling community generated electricity across several sites to feed a single community benefit fund) can also make projects more attractive to local businesses and investors.

However, community organisations within our research noted they often struggle to find suitable organisations or to explain to key individuals within the organisation why this would benefit them and their local community.

The Scottish Government could support this process by convening public and commercial sector energy users to raise wider awareness of local or community energy power purchase arrangements, and highlight the option of partnership with community energy in public and commercial sector procurement guidance.

Action: Develop new funding models for local and community approaches to energy efficiency, retrofit and advice

Energy efficiency and retrofit services have been a rapid growth area for community energy. However, stakeholders note that community-led efficiency and retrofit relies heavily on short-term competitive grant funding, with business models still in early stages. This makes it challenging to develop effective, sustainable community-led solutions.

To enable this value, community organisations working in this space note there is a need to support them to develop new business and delivery models, potentially in partnership with local authorities. Building on existing funding routes such as CARES, the future National Public Energy Agency could work with community and local partners to support the coordination of investment and development of new community efficiency and retrofit funding arrangements.

Action: Work with the Convention of Scottish Local Authorities (COSLA) and local authorities directly to identify and address key friction points within the local energy planning, approval and delivery processes

In our People’s Panel, participants noted that communities and local authorities should face a minimum of red tape in getting projects up-and-running, allowing them to innovate, demonstrate and deliver value sooner. Local authority stakeholders also noted that this is a key issue.

Because projects must navigate a range of local authority departments and sign-off processes (not including wider processes such as securing grid connections and meeting regulatory requirements), they can be held-up or fail due to political timeframes and pressures such as local or Scottish Government elections. There is thus a need to ensure that projects can progress more efficiently within and alongside these democratic processes. Local authority stakeholders and examples from other local energy projects such as GreenSCIES in London suggest that streamlined project processes within local authorities (potentially with a single embedded local energy officer) would help to ensure projects can progress overall, both within election cycles and in the longer-term.

Enhance ownership and governance

Recommendation 3: Expand community and local ownership of energy, ensuring that ownership and governance of projects are accessible, accountable and transparent, with proactive inclusion of marginalised or excluded groups.

Who owns local and community energy projects can have a direct impact on how much they contribute to just transition outcomes. Research from Aquatera (2021) compared 9 community owned winds farms against 4 commercial wind farms and found that the community-owned wind turbines in Scotland have generated, on average, 34x more in community benefit payments than the developer-led projects.

Where projects are locally or community owned – particularly by communities and local authorities – evidence suggests that the main outcomes tend to be aligned with just transition principles (Stewart 2021; Creamer et al 2019; Hanke et al 2021). This can also enable more value to be captured locally overall than, say, projects led by developers alone. As such, enabling more local and community ownership of energy can help to deliver greater value against just transition outcomes.

Community and local ownership is not fairer by default, however, with a need to ensure that ownership and governance structures are fair, accessible, and transparent (see Section 1.14).

Action: Develop clear targets for community energy

Although cited as a priority for Scottish Government in the Local Energy Policy Statement, community-owned projects account for only 11.1% – 101 megawatts – of total operational local and community energy capacity as of December 2023 (Scottish Government Energy Statistics Hub, 2023). Scottish Government does have a target of 2 gigawatts operational local and community energy by 2030. However, this target also includes non-community owned projects such as public sector and local authority projects, and projects led by farms and estates.

Research shows that clarity in government targets can provide a signal to stakeholders to help stimulate innovation and action among businesses, developers, and communities towards net zero – including in community energy when paired with wider measures and support (Hewitt et al 2019; Yeow et al 2017). Community energy and just transition stakeholders similarly note that making clear how much of the 2030 target is expected to be community-owned would set a clearer vision for communities overall.

As a means to stimulating more community ownership and innovation and redoubling this ambition within the final ESJTP, the Scottish Government could outline how much of the remaining 2 gigawatt target is to be met by new community-owned projects specifically.

Action: Enable greater community ownership through local energy planning

Identified by both local authority and wider local energy stakeholders, local energy planning presents a new opportunity to support community ownership and more democratic input on local energy ambitions overall. Within local energy planning processes, such as LHEES, LAEP or heat network zoning, local authorities can identify sites that would be appropriate for community energy projects, particularly generation and heat, and work with community organisations to develop them.

In theory, this is a win-win situation: community energy organisations have a wider scope of potential projects, while local authorities can be supported by community organisations to deliver against their energy ambitions.

Action: Develop the potential for local authority shared ownership

While the Scottish Government has set out its principles for community shared ownership of renewable energy developments (2019), there is no similar guidance at present for local authorities. With the development of the Regional System Planner at UK-level and other trends towards greater local authority participation in energy decision making and projects (Ofgem, 2023; PwC, 2022; Green Finance Institute, 2022), local energy and finance stakeholders highlight that this could be a useful vehicle for establishing more local ownership of energy assets.

Where communities are deemed less-well equipped to participate in shared ownership, providing guidance for local authorities to invest in shared ownership projects could create a new avenue to capture value from larger developments, potentially creating new local authority revenue streams or community benefit funds. This is already included in shared ownership guidance in Wales, for instance (Welsh Government, 2022). Building on Scottish Government’s existing Community Shared Ownership Best Practice Principles (Scottish Government, 2019), working with COSLA to understand the potential role and opportunity for local authorities in shared ownership arrangements could be a useful undertaking.

Participation and engagement

Recommendation 4: Ensure that all groups and communities can realistically engage with local and community energy projects, to participate in governance and decision making, and shape ideas from the beginning.

Often those groups typically already excluded or disadvantaged in society also face risk of exclusion within local and community projects (Knox et al 2022). Without ensuring that those most at-risk of exclusion can engage and participate directly, there is a risk that projects do not reflect the needs of those groups and people, and that those people are in turn excluded from wider benefit. Table 6 illustrates key barriers for specific excluded groups as identified in our academic literature review.

Expanding capacity and outreach as outlined in Recommendation 1 can go some way to overcoming this issue. However, it is important to consider the specific needs of these groups to ensure they can participate in, and benefit from local and community energy projects. This includes paying attention to project design, engagement, decision making, governance and benefit allocation (Knox et al 2022; Huggins 2022).

Table 6: Groups with additional barriers to engagement and participation

Action: Ensure best practice principles for co-design and engagement

Ensuring as many people as possible can help to shape, participate in and benefit from local and community energy requires proactive, targeted and meaningful engagement with all groups within a community or area – particularly those most disadvantaged or at risk of exclusion already.

To do so, our People’s Panel echoed that there is a need for a shared standard of best practice in community engagement across local and community energy projects, starting at the earliest possible stage with broad promotion, to allow citizens and communities to meaningfully co-design projects from the very beginning. As highlighted above, using trusted intermediaries can be one effective way of reaching groups most at-risk of exclusion, although other methods such as targeted doorstep or community engagement may be more appropriate in some circumstances.

Several organisations such as the Scottish Community Development Centre and Project LEO in Oxfordshire have already created standards for community engagement and local energy respectively (Huggins 2022). For example, the Scottish Government and COSLA recently delivered their own ‘Planning With People’ initiative which outlines best practice for community engagement on local health and social policy. The Scottish Government has also been leading a trial of green participatory budgeting. This activity can provide useful groundwork for increasing local and community energy.

Our research therefore suggests that the Scottish Government should build on other examples of best practice, such as the Good Practice Principles for Community Benefit in Onshore Wind Developments (2019) and encourage local authorities, community energy groups, developers and relevant stakeholders to adopt a shared best practice standard for citizen and community engagement in all new local and community energy projects.

Action: Make governance of projects more transparent, inclusive and accountable

Once projects are established, how they are then governed (who makes decisions, what the processes for decision making look like) has key justice implications. Issues have been noted in the energy justice literature (see Hanke et al 2021), for instance, with community benefit funds that are determined by developers and spent largely by those more active and engaged members of a community, excluding those more socially isolated, meaning outcomes could fail to reflect their needs.

Likewise, experience from previous innovation projects shows that local projects can be decided by leading partners and organisations, with limited local or community direction. Ensuring proactive engagement with communities and inclusive, accountable governance structures that do not rely on people paying money to participate can help increase public support and promote fairer outcomes and processes.

Action: Formalise the role of third sector and advocacy organisations as trusted intermediaries

Trusted intermediary organisations such as fuel poverty charities, community groups, mutual aid initiatives, faith groups and third sector more generally are crucial to supporting people into local and community energy projects, and net zero more widely (Slee, 2020; Stewart, 2021). Such organisations can support engagement and outreach with often-excluded communities, and help to advocate for their needs within policy, project and development processes.

However, third sector and fuel poverty stakeholders note consistently that these organisations are under resourced – an issue made especially acute during the recent energy crisis (Citizens Advice, 2023). This means that although many organisations are open to supporting energy and just transition projects, they are severely limited in their capacity to do so. Funding for these organisations tends to be competitive on an annual basis, meaning that staff spend a lot of time applying for the next round of support. This also means that longer-term capacity building, upskilling, and working with people and places is difficult.

Third sector stakeholders working in equalities and fuel poverty in particular, along with just transition researchers, highlight that more stable, longer-term resourcing for trusted intermediary organisations such as their own (including established community energy groups) would help to enable better capacity building and representation of excluded communities, along with clarifying the role Scottish Government expects these organisations to play across the ESJTP. The Climate Policy Engagement Network could provide one forum for engagement with these partners.

Develop finance, funding and investment

Recommendation 5: Develop sustainable finance and business models that ensure those who can’t afford to pay are not excluded from participation or benefit, and that maximum value is retained locally with just transition outcomes explicitly prioritised.

Local and community energy projects rely on a range of finance and funding sources (Cairns et al. 2023). Where this funding comes from, who pays, and what happens to the revenues are all important just transition questions.

All funding types can support NJTOs and a wider just transition in theory, but not necessarily by default (as discussed in section 3).

Table 7 outlines the key issues with different funding models. As such, supporting a just transition means ensuring that finance, funding and investment are fundamentally aligned with just transition outcomes first and foremost.

Table 7. Overview of finance and funding sources for local and community energy

From this analysis, there are four key issues for just transition outcomes:

• Share offers are often exclusionary of lower income groups within community or shared ownership. However, individual projects can stipulate exemptions to ensure people can still participate, with a need to encourage this on a consistent basis.
• Grant and innovation funding is often short-term and overly innovation-focussed, with a lack of support for scaling-up or more social and business model innovation. It can also prioritise innovation first with just transition value treated as secondary, while projects often wind down with no lasting legacy for communities.
• Public funds are available and welcome, such as in the recent Heat Networks Fund, although there is a strong sense that these are not adequate at present for local authorities to fully deliver LHEES, for instance, or for community energy projects to be established at scale.
• Private finance is playing an increasing role in local authority and larger-scale integrated projects, such as Bristol City LEAP. However, stakeholders interviewed across different sectors are cautious about previous experiences with the Public Finance Initiative and the risk that private investment may lead to value leaving local areas.

Action: Explore new private sector funding models for local and community energy

With more public-private finance models, there are various opportunities for businesses and organisations to invest in local and community energy projects, which in turn can support other just transition outcomes (such as decarbonisation & efficiencies, and citizens, communities & place). Many already do invest in community energy share offers, via community or municipal bonds, or through partners such as Triodos Bank and Abundance Investment.

However, stakeholders in the finance and investment space note that without the Feed-In Tariff, the return for local or community projects is generally less attractive unless projects get to a larger scale (e.g. a high number of aggregated PPA agreements or more ambitious integrated local energy systems).

Closer working between the Scottish Government and the Scottish National Investment Bank (SNIB) on community and local energy is one viable option to help to overcome this issue. While the SNIB typically invests in £1 million+ projects, it could begin to work closely with local and community sectors to develop new models and instruments and help build better financial networks. It could also help aggregate projects to create a larger, packaged proposition which is more lucrative to investors. 3Ci’s (2022) regional net zero investment forum, which brings together the finance community, local authorities, policymakers, developers, businesses and community enterprises in different regions across the UK, has already made some progress on this.

Action: Incentivise just transition outcomes in policy, procurement, and funding decisions around local energy projects or systems – especially where commercial, innovation or private finance are involved

There is also general understanding across stakeholders that private investment has a strong role to play in reaching net zero and delivering more ambitious local projects (Green Finance Institute 2022; UKRI and Regen, 2022a). Our People’s Panel participants likewise told us that it does not strictly matter where money comes from, so long as the primary beneficiaries are people and places first, with strong consideration of just transition outcomes and an offer of shared ownership as standard.

To ensure this, where innovation or private finance is involved in local and community energy projects, there is a need for just transition guidance in funding and procurement processes. This should also be considered together with Community Wealth Building and relevant National Planning Framework legislation.

Action: Ensure adequate strategic funding for local energy delivery (and beyond)

Beyond project funding models, local authorities note that short-term annual budget cycles make it difficult to develop longer-term projects or strategies. Local authority and wider UK local energy stakeholders note that this current model of funding has led to a disparity across local authorities in energy efficiency schemes in particular, with many drastically underspending on their allocated budgets.

This makes it difficult to mobilise local jobs and skills to meet decarbonisation and efficiency plans (and fuel poverty targets), limiting the appetite for businesses to emerge, upskill, or retrain to deliver on these ambitions – and for investors. Skills and jobs for the delivery of energy projects are a well-cited and evidenced barrier to progress here more generally (Chitchyan and Bird, 2022; UKRI and Regen, 2022b). This was also highlighted in the Scottish Parliament’s ’Role of local government and its cross sectoral partners in and delivering a net-zero Scotland’ report (Scottish Parliament, 2023).

Our research shows the importance of reviewing funding required for the on-the-ground delivery of local energy plans and projects such as LHEES, and reforming existing budgets and processes to allow for more strategic, longer-term planning and investment. Much of this work is already underway in the delivery of the Heat in Buildings Strategy. As such, there is a need for the Scottish Government to accelerate efforts with local authorities to develop more appropriate funding models, and deliver long-term budgetary plans as a signal to investors, and to industry, to mobilise skills and supply chains.

Open up benefits and beneficiaries

Recommendation 6: Open the benefits of local and community energy projects to as wide a range of people and places as possible, including everything from household decarbonisation and bill savings to skills and supply chains.

As evidenced throughout this report, local and community energy can carry substantial benefit against Scotland’s NJTOs and for local people and places more broadly.

However, not everyone can currently experience those benefits directly, due to financial, physical or other reasons. For instance, people on low incomes will struggle to buy in to community share offers and so will not receive any financial return from projects, nor have a say in project governance.

Similarly, people in the private rented sector or multi-occupancy buildings will struggle to benefit from initiatives which include new technologies or energy efficiency measures due to legal and physical challenges.

In addition, some of the benefits identified in previous sections of this report have yet to be fully enabled. This includes the realisation of new jobs and skills, which is a common issue in net zero energy delivery more broadly (Chitchyan and Bird, 2022; UKRI and Regen 2022b).

Beyond the recommendations already provided, there is thus a need to consider how to enable benefits of all kinds that reach a wider number of people, and that carry impact against Scotland’s net zero, energy and just transition ambitions at scale.

Action: Conduct policy engagement with identified groups (e.g. low incomes, those in the private rented sector and multi-occupancy buildings) to establish new ways for them to participate in and benefit from local and community energy projects

Where local or community energy projects include installing measures in people’s homes which deliver financial, health or environmental value – such as solar and storage, heat pumps, heat networks, efficiency or as part of wider local energy systems – certain groups face key barriers to benefitting directly.

Research such as that by Knox et al (2022) outline how people living in the private rented sector in particular will struggle to participate and experience benefit due to legal questions over ownership and responsibility. This is also true of those living in flats with different housing tenures.

People living on lower incomes will likewise struggle to invest in community share offers, meaning they have limited opportunity to gain individual returns or participate in the governance of projects that require up-front investment as a result.

As such, there is a need to work directly with these groups, tenant associations such as Living Rent, landlords and local authorities to develop frameworks that allow people living in those situations to also participate and benefit. As outlined by our People’s Panel, this should also encourage projects to deliver wide benefits to the local community, not based solely on ability to pay or invest.

Action: Work with education and training providers, industry, and local energy stakeholders to set out the skills and business opportunities for local and community energy

Local jobs and skills are often slated as a key opportunity from local and community energy, including within the Scottish Government’s Local Energy Policy Statement (2021). However, these opportunities are still to materialise at scale in Scotland and the UK more broadly, with a stubborn reliance on volunteers in the community sector in particular (Institute for Public Policy Research, 2023; UKRI and Regen, 2022; Community Energy Scotland 2022; Climate Change Committee 2023).

Reviewing the Heat in Buildings Supply Chain Delivery Plans and Climate Emergency Skills Action Plan (CESAP) could provide an opportunity to outline requirements for local energy skills specifically. This could include working with energy and training organisations such as Skills Development Scotland and local and community energy partners including industry and local authorities, to provide a clear analysis of opportunities within the local and community energy sectors.

This could also include specific assessment of the jobs and skills needed to deliver on the 2 gigawatt target (and to enable local and community energy at scale more broadly), and an articulation of pathways for people and businesses to access new opportunities.

Policy dependencies and responsibilities

Policy dependencies

Outside of the immediate local and community energy policy space, there are some key policy interdependencies that should be considered when aiming to better enable local and community energy approaches. Working across these areas will be crucial to ensuring effective delivery of local and community energy going forward.

Based on the research covered in this report and Regen’s own critical analysis, Table 8 sets out potential additional actions for a (non-exhaustive) list of key dependencies that could help move local and community energy forwards for just transition outcomes.

Table 8: Policy dependencies and suggested actions

Reserved policy areas

As aspects of energy policy and regulation in the UK are reserved, there are limitations to the work that Scottish Government can do to fully enable local and community energy. Many of the policies required to support local and community energy – particularly in energy market regulations which govern electricity supply, Feed-in Tariffs or Contracts for Difference, and recognising the value that local energy systems can offer to the energy system more widely within regulatory incentives – are not within the Scottish Government’s remit.

However, there are a number of key reform packages and opportunities currently open to the Scottish Government to seek to influence the UK Government to promote Scotland’s local and community energy and just transition ambitions. These include but are not limited to:

• Review of Electricity Market Arrangements (DESNZ, REMA)
• Contracts for Difference (DESNZ, separately and under REMA)
• Review of Local Governance and Institutions and the development of the regional energy strategic planner (Ofgem)
• Grid connections reform (Ofgem, National Grid ESO)

Table 9 gives a high-level overview of key reserved issues. This sets out some of the primary issues, how primed each currently is for delivery, and some suggestions for what is required to meet Scotland’s local and community energy and just transition ambitions at once.

Table 9: Reserved issues

Conclusions

This report has analysed the potential role of local and community energy in delivering against Scotland’s National Just Transition Outcomes. This analysis and the subsequent recommendations have been informed by extensive review of literature and research, stakeholder engagement and discussion with citizens directly via our People’s Panel.

From this analysis, it is clear that local and community energy can be a critical part of Scotland’s just transition ambitions, contributing across all of Scotland’s National Just Transition Outcomes. This contribution could be supported through locally-tailored solutions and maximising inclusive ownership, participation, governance and benefit captured from Scotland’s immense energy landscape.

Enabling this requires supporting the growth of the local and community sectors overall, and building just transition principles into those projects and processes. The ambitions and recommendations throughout this report set out how to achieve this in practise, with key actions for Scottish policymakers and delivery partners.

Our research has also found key barriers to delivering against these outcomes across sectors: limited resources to build capacity for local and community energy projects in underserved areas; challenges around skills and project delivery processes particularly within local authorities; justice and equity issues within projects themselves; and lack of appropriate finance and business models.

Beyond the research and recommendations presented here, we identified other areas that would benefit from further, specific exploration within the local and community energy and wider energy sectors. These are:

• community ownership of land and housing, the role of local authorities in supporting these and how energy can be brought together within that; and,
• repowering and end-of-life onshore wind projects, and how local authorities and communities can start to take ownership of these; as many wind farms come to the end of their first contracts, there is a need to work with local energy stakeholders and developers to fully understand the potential for community ownership.

While relevant, more detailed analysis of these two issues would help shine a light on potential further opportunities for the local and community energy sectors, and on the delivery of even further value against Scotland’s National Just Transition Outcomes.

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Appendices

Appendix A: Methodology

We used three key methods in the delivery of this project. These were:

• Systematic review of academic and policy literature
• Interviews with key stakeholders
• Deliberative “People’s Panel” with Scottish citizens (Appendix B)

These methods were selected to give us as rounded a view of the opportunities and barriers for local and community energy as possible. More details on review and interviews are given below, with a more extensive overview of the People’s Panel in Appendix B.

Systematic review of academic and policy literature

Leveraging previous academic expertise of the project team, we conducted a review of relevant literature in the field of local and community energy with reference to a just transition. In total, we reviewed nearly 100 documents, including peer-reviewed journal articles, consultant reports, case studies, and policy documents from the Scottish and UK Governments.

Articles were sourced using search terms in Google Scholar. We first searched “local energy”, “community energy”, and “just transition”. We then expanded our search to include local/community energy and the different just transition outcomes.

Policy documents were sourced from the Scottish and UK Government websites, online search engine searches, and early informal interviews with key local and community energy policy experts. Within Regen we have vast experience of the local and community energy space, including developing the Community Energy England, Scotland and Wales state of the sector reports for 2021; delivering ongoing engagement and convening with community energy organisations and the wider energy sector via our network-funded communities programme (Regen 2023); and advocating for community energy within policy and regulatory consultations such as delivering benefits from offshore wind (and supporting community organisations to do the same). Finally, we sourced cases by reviewing innovation projects such as Prospering from the Energy Revolution, and through asking stakeholders for recent developments.

Once documents were sourced, they were reviewed for evidence and analysis around the eight NJTOs specifically, as well as lessons for delivering more just processes and outcomes. These were collated within a single spreadsheet, with this spreadsheet then discussed by the project team to establish key themes and content.

Interviews with key stakeholders

Once this review was complete, we interviewed 22 key expert stakeholders working across local and community energy, community energy organisations, local authorities, innovation, renewable energy businesses, equalities and social justice, just transitions, and third sector. This diverse base of people was chosen to help give a rounded view not just of local and community energy, but to glean insights from relevant sectors to help shape a future look at local and community energy to ensure it works for NJTOs. These were identified through existing Regen, Scottish Government and industry networks.

It is worth noting that there was higher representation from both citizens and local and community energy practitioners than e.g. renewable energy developers and businesses in this process. This was deliberate – citizens and local and community organisations, particularly those working on just transition issues, have been less often engaged in such discussions yet can provide crucial insights on how to best open up local and community energy for a wider range of just transition outcomes. However, recommendations in turn reflect more the perspective of those stakeholders. Further engagement with energy developers and businesses would help make recommendations more robust.

These interviews took place online during the months of February-April 2023. Each lasted between 45 minutes and 1 hour. Feedback was anonymised during the analysis process. We asked specifically where people had seen local and community energy working for just transition outcomes already, the key issues that local and community energy might face in working for just transition outcomes or processes, where they felt local and community energy could add more JT value with the right support, and how we could best enable this (relevant to people’s area of expertise). Questions were developed from a combination of evidence from the literature review, and to target the key research aims of the work agreed at project inception.

To supplement, we also held an informal online workshop of local and community energy stakeholders in the UK, to discuss these themes in an open forum with experts from a more technical and specialist perspective. In this workshop, stakeholders included some of those interviewed, but were mostly made up of local and community energy stakeholders from outside Scotland, allowing us to glean a more rounded view of the sector and recent developments elsewhere in the UK. This workshop did not influence recommendations directly, but rather helped us track any new and emerging trends in this space identify key just transition questions (particularly around local project processes, innovation, system operation and governance) for further investigation in the Scottish context.

Appendix B: People’s Panel

To fully understand how local and community energy can support all communities and regions across Scotland, Regen commissioned Shared Future to co-design and run a People’s Panel.

A People’s Panel is a deliberative process, bringing together citizens from a sample of the population to learn about a topic and ‘co-design’ policy recommendations. People’s Panels, and other types of deliberative processes, are particularly powerful tools for addressing policy issues that impact and involve people. They allow for ideas – such as different models of community and local energy – to be tested amongst the target population, they help explore barriers around engagement and participation, and they add democratic legitimacy to policy development. The goal of our People’s Panel was to answer the question:

“The way we use energy in our homes and communities is changing, with many communities and councils developing their own solutions.

How should this be done so that it involves and benefits people in a fair way?”

To address this question, Shared Future recruited 22 people from across Scotland to participate in four online sessions over the course of three weeks. In these sessions, participants hear from ‘expert witnesses’ who present on the relevant topic of the day in clear terms, with participants discussing what they’ve heard and questioning witnesses for more information.

Expert witnesses were chosen by the wider project team (including our academic steering group) as people who either (a) were considered experts or leading practitioners in their field, and/or (b) led an interesting real-world case study. This did not include a “traditional” commercial renewable energy developer. Experts were briefed extensively by the Shared Future team as an impartial partner, to eliminate biases and ensure that presentations were as clear and understandable as possible. The aim was not to promote local and community energy, but to present participants with different models, examples and ideas to understand their perspectives. We had two expert witnesses per each session, covering:

• How the energy system works and how it is changing to become more local and renewable (energy systems expert Calum Watkins – Smarter Grid Solutions, and local energy expert Rebecca Windermere – Regen)
• Community energy (Glasgow Community Energy; Local Energy Scotland who replaced Community Energy Scotland due to scheduling clashes)
• Local energy (North Ayrshire Council; the Blairgowrie Heat Project; smart local energy expert Jess Britton – UKERC) and
• Larger developments and shared ownership (Ripple Energy, Local Energy Scotland)

From these sessions with witnesses and wider discussions, participants then deliberated and worked together to identify 20 key principles for developing local and community energy such that it involves and benefits people in a fair way. These are grouped into 7 key themes (below).

Of these participants, only 1 had heard of local or community energy before. A stratified random sample of the population was used to gain perspectives from people who had not worked in this space before, and from diverse social and economic backgrounds. The same 22 participants attended each session, and were paid £110 each in vouchers of their choosing for their time.

Theme 1) Definitions

This theme relates to clarity of definitions surrounding the energy project itself, the roles and responsibilities of those involved, and the budget.

It includes three principles:

• How the project will work is clear; how long it will last, what are the personal and community benefits of being involved etc. This is made easy to understand.
• It has been agreed and is clear what roles and responsibilities there are and how much time commitment is needed by people who want to take part. This will enable people to play to their strengths and feel ownership.
• Transparency of the budget is clear to all.

Theme 2) Goals and outcomes

This theme brings focus to how aims, success metrics, shared values, priorities, and benefits are established within local and community energy developments.

It includes four principles:

• The aims of the project and what success looks like is clear to all and has been agreed by consensus.
• Shared values are agreed by all involved.
• Priorities are set but, not everything at once, start small and scale it up as more people get interested.
• Fairness: everyone has to benefit, with benefits being evenly distributed.

Theme 3) Participation

This theme takes a very broad view of issues related to participation, including raising awareness of local and community energy generally, engagement and promotion within the community itself, participation opportunities across the whole community, and routes for democratic governance structures.

This theme includes six principles:

• There must be large-scale awareness-raising of the concept of community/local energy so that everyone understands its benefits and what your individual / community entry point might be.
• Developers should be mandated to engage with communities at the earliest possible stage (before planning) to ensure that benefits are relevant to the community and to ensure that there is forward planning so that the community is happy with how the land, and any infrastructure, will be developed or left at the end of the project.
• The project is well promoted to everyone within the community.
• Collaboration is encouraged so that lots of people can get involved and work together sharing lots of ideas.
• Flexibility means that input can be heard from all parts of the community.
• The way that decisions are made is clear and agreed. It is democratic so people are able to express views, and misgivings, it is not controlled by one person and all who have a share (no matter how small) have a vote. At least a proportion of shares must be affordable for those on a low income. Changes are consulted on.

Theme 4) Support and risk

This theme talks to the processes of delivering local and community energy developments, ensuring that support is provided to the community to support project engagement or delivery, and that risks to the community are minimised.

It includes two principles:

• There is support in place all the way through the project so that no-one feels left alone and appropriate extra training is provided. Funding for community-sourced leadership roles should be mandated where it supports equitable and consistent involvement.
• No unnecessary risks are taken.

Theme 5) Local use of energy

This theme relates to Panel members’ perspectives that energy generated locally should also be used locally. It includes one principle:

• Wherever possible the energy generated should be used by the local community.

Theme 6) Shared ownership opportunities

This theme focuses specifically on shared ownership energy models and talks to the mechanisms through which people can get involved with shared ownership projects.

It includes two principles:

• In a shared ownership project, there must be the opportunity to invest throughout the lifetime of the project and a clearly defined timeframe for how long it will remain publicly owned.
• In shared ownership projects, developers should have profits capped at a percentage level to ensure they are not making excessive profits whilst there are any households left sitting in the cold.

Theme 7) Roles for government

This theme speaks to the structures that need to be put in place to support the fair growth of community and local energy across Scotland. While many of the other principles and themes relate to specific instances of community and local energy development, this theme is more focussed on widespread action and equality of opportunity across the country.

It includes two principles:

• There has to be conclusive and resounding support (investment and policy) from all levels of government that mean widespread community and local energy is a reality across all our communities.
• To help ensure fairness, national government needs to ensure that all councils are a) able to invest in community energy projects and be held to account if they don’t do so and b) face a minimum of red tape in achieving innovation.

Support for Principles by theme

This theme

Figure 1 depicts the degree of support held by Panel members for each principle, grouped according to the seven themes outlines above.

Across all themes and principles, the average ratio of support (strongly support and support) to opposition (oppose and strongly oppose) is 52:1. For every vote of opposition, there were 52 votes in support, with only 6 total votes opposing principles in total, showing overwhelming agreement with almost all principles developed.

Appendix C: Local and community energy just transition outcome impacts

Table: Community energy

Table: Local energy

Table: Integrated local energy systems

© The University of Edinburgh
Prepared by Regen on behalf of ClimateXChange, The University of Edinburgh. All rights reserved.

While every effort is made to ensure the information in this report is accurate, no legal responsibility is accepted for any errors, omissions or misleading statements. The views expressed represent those of the author(s), and do not necessarily represent those of the host institutions or funders.

www.climatexchange.org.uk

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DOI: http://dx.doi.org/10.7488/era/3737

Executive Summary

Overview

Scotland’s electricity system is undergoing a transformation with rapid increases in installed wind and solar electricity generating capacity. This is coupled with the phase out of nuclear and unabated gas power stations.

This will impact on Scotland’s electricity system security of supply, which has historically relied on large, centralised fossil fuel power plants. These can ramp power production to meet demand, in addition to grid network connection to the rest of Great Britain. Here ‘security of supply’ refers to the ability of the system to reliably and continuously provide a sufficient amount of electricity to meet the demands of consumers.

In this report, we explore issues around security of supply in Scotland’s electricity system in the transition to net zero by 2045. We examine international examples of national and regional electricity systems transitioning to net zero and review the potential impact of electricity market reform. We use scenario modelling to quantify security of supply and import/export metrics for the expected technology pathway in Scotland.

The future security of supply of Scotland is subjected to stress tests, including disconnection of offshore wind farms; low variable renewable power output; unavailable gas power generation in Scotland; unavailable interconnectors; battery storage failures; and an unavailable connection to the rest of GB. The report also looks at the security of supply of a self-sufficient Scotland, with no interconnection to Europe or the rest of Great Britain, in addition to a low capacity and high demand scenario to further test Scotland’s future electricity system.

Key findings

• Examples of national and regional electricity systems operating with high proportions, in excess of 100%, of renewable electricity are typically dominated by hydropower and pumped hydro storage reservoirs. These are dispatchable and offer high levels of security of supply.
• Scotland and Denmark are leading examples of national electricity systems integrating large shares of variable renewable energy sources, but rely on imports with neighbouring countries.
• Potential changes to electricity market arrangements such as splitting the wholesale market, locational pricing and an enhanced capacity market could have impacts on future investment in renewables and flexibility technologies in Scotland.
• Under the System Transformation scenario there will be a reduction in traditional firm generation capacities in Scotland. This includes no nuclear and reduced gas power plant generation when changing to carbon capture and storage technology. However, these losses will be offset by vast increases in wind and solar installed capacity, as well as increasing low-carbon firm generation capacity in the form of biomass, hydrogen and abated gas power plants.
• Security of supply metrics for Scotland in the System Transformation scenario for the years up to 2045 were found to be within the current GB reliability standards and comparable to current levels. Security of supply in Scotland improves in the transition towards net zero by 2045 due to large increases in generation capacity and storage.
• Peak demand in Scotland is expected to rise from around 5000 MW in 2021 to around 9000 MW by 2045 but is exceeded by generation, even when considering expected availability in real time. While the generation capacity in Scotland may seem excessive in the context of security of supply in this scenario, it is utilised to decarbonise and provide security of supply to GB as a whole.
• Scotland will continue to be a net electricity exporter to the rest of GB and net exports will increase from current levels. There will be an increase in the level of import from the rest of GB due to increased demand, coupled with increased reliance on variable wind power generation, which leads to more imports during low wind periods.
• Testing of the future Scottish electricity system, assuming low installed capacity for thermal power plants, low B6 boundary expansion and high future peak demand, shows lower security of supply in 2030 than the GB reliability standard.
• In 2025 and 2030 disconnection with the rest of GB has the highest impact of all of the stress tests conducted, followed by unavailable interconnectors and gas supply issues. This implies that there is a high reliance on imports from and exports to the rest of GB in maintaining the capacity adequacy in Scotland. However, its significance is negligible from 2035, when there is a large increase in offshore wind capacity and additional capacity of battery storage, pumped hydro, hydrogen power plant and biomass.
• A self-sufficient Scotland with no connection to the rest of GB and no interconnector capacity would violate the GB reliability standard in the years 2025 and 2030, mainly due to periods of low wind and renewables output without sufficient dispatchable supply capacity. However, by 2035 the security of supply metrics are within historical values and improve further in the following years. We find 250 MW and 1000 MW of additional equivalent firm capacity would be needed in 2025 and 2030 to meet minimum reliability standards and historically typical standards respectively. This would be the equivalent of an additional 1,553 MW to 6,211 MW installed capacity of offshore wind.

Glossary

Introduction

Background and aims

Scotland is committed to net zero greenhouse gas emissions by 2045 through the Climate Change (Emissions Reduction Targets) (Scotland) Act 2019 [1]. This means net zero emissions across all sectors of the economy, including from the energy system. In the power sector, traditional thermal generation, such as nuclear power and gas power plants are being retired and there are ambitions for realising 8-11 GW offshore wind capacity by 2030 [2]. Under some net zero scenarios this could increase to more than 35 GW by 2045 in Scotland [3]. Additionally, under National Grid’s ‘Leading the Way’ scenario in Scotland solar PV rises from 0.5 GW in 2021 to 6 GW in 2045, and onshore wind rises from 9 GW in 2021 to 27 GW in 2045.

This raises the importance of security of supply in Scotland with an electrical system that has high levels of weather-dependent wind and solar energy. The transition to net zero brings new challenges to Scotland’s electricity system security of supply:

• Torness nuclear power plant is due to close before the end of this decade resulting in the loss of the baseload output from this electricity generator.
• Peterhead gas power station may close as an unabated gas power plant and be replaced by a gas power plant fitted with carbon capture and storage technology. It is uncertain whether new carbon capture power plants can be operated flexibly or will be required to produce electricity round-the-clock.
• Increased reliance on intermittent renewable energy sources causing greater disparity between generation and demand on hourly, daily, monthly, and seasonal timescales.
• Increased need for electrical network expansion and reinforcement to transport renewable electricity to high demand areas.

The emissions reduction pathway shown in the 2020 climate change plan update [4] accordingly sets out a vision for net zero emissions from the electricity sector by 2029.

In this report, we:

• Investigate international examples of national electricity systems operating/moving towards reliance on renewables.
• Review expected/planned policy or regulatory developments, such as locational pricing, which could impact the future system.
• Assess technology developments needed in Scotland to ensure a secure and reliable supply of low and zero carbon electricity to 2045.
• Assess the likely impacts on transfers of electricity from/to Scotland and the rest of GB, in a Scottish electricity system powered almost entirely by intermittent renewables.
• Calculate additional volume and type of generation that would be required for Scotland to have an entirely self-sufficient system (also including black start capability).

Security of supply

Security of supply in electrical power systems is the ability to match supply and demand with high probability, both under normal and unexpected conditions. This includes the coldest periods when peak demand often occurs; during outages of large power plants or interconnectors; and dark, windless periods when there is low renewable generation.

Challenges for future security of supply

Meeting the peaks in electrical demand is key in determining security of supply. If this demand can be met with high probability, then it is likely that all other periods with lower demand can also met. However, in systems where a high proportion of generation is from variable renewable sources then there will also be periods when high generation coincides with lower demand, which can lead to excess generation. Periods of excess generation is not the focus of this report but it is recognised that this can also provide challenges in an electrical system, such as costs of constraints, and that these periods require reliance on flexibility technologies such as storage and interconnection.

Peak electrical demand is expected to grow in the UK^[1] from around 60 GW seen for the past decade to 100 – 115 GW in 2050 [Figure 1]. These rises are strongly driven by electrification of heat and transport.

Figure 1 Peak demand during average cold spell increasing according to Future Energy Scenarios

In the future, it is expected that there will be increasing flows of power between Scotland and the rest of GB. The extensive wind resources, both onshore and offshore in Scotland, offer high and consistent wind speeds which makes Scotland an attractive place to build wind farms. However, electricity demand is far greater in England than in Scotland. In 2021 peak electricity demand was around 11 times higher across the rest of GB (55 GW) compared with Scotland (5 GW). National Grid’s ‘System Transformation’ scenario from the Future Energy Scenarios (FES) predicts broadly similar levels of installed wind capacity by 2050 (onshore and offshore) in the rest of GB (around 71 GW) and in Scotland (around 59 GW) [3]. This will lead to more reliance on the electrical network for transmitting the necessary electricity to ensure security of supply on both sides of the Scotland/England power system boundary.

Security of supply in the UK in National Grid’s Winter Outlook

Peak electricity demand often occurs during cold weather, and National Grid publish a winter outlook on security of supply every year. The report provides analyses of forecasted weather, expected power plant issues, and estimated import and export capabilities of interconnectors to Europe. The impacts on probability of the UK electricity system to be able to reliably meet electricity demand are also assessed. For more information on the 2022/23 winter outlook see Appendix 12.1.

Under normal conditions the electrical power system at present meets security of supply thresholds, but wider geopolitical issues have shown that it is vital to consider ‘unlikely’ stress events to the system. The winter outlook gives the current view on security of supply in the short-term but given that it takes years to build electrical power infrastructure it is important to consider how security of supply will evolve in the future.

The transition to net zero is informed by creating scenarios for the expansion of capacities of generation, demand, flexible technologies such as batteries and pumped hydro, and electrical networks.

Issues around operability

Black starts are the process for recovering the entire power grid following a highly unlikely^[2] complete shutdown. However, not all generators have black-start capability. Conventionally, it is provided by a limited number of large coal, gas, and diesel generators. Following a highly unlikely event of a total or partial shutdown of the national electricity transmission network, black start plants can start independently, by using on-site equipment and fuel. They are independent of wider system input or specific weather conditions and can set up a skeleton network. Gradually different components can be reconnected to re-establish normal operation.

Wind turbines were previously viewed as unsuitable for black start due to dependence on external electricity before they can begin generating power. However, some of the latest designs are capable of self-starting. For example, in 2020, the 69 MW Dersalloch wind farm provided a black-start function through alternative control of power electronics using a virtual synchronous machine approach to restart part of the Scotland grid [5]. Battery storage, which has seen fast growth in UK, can also contribute to a black start. National Grid has committed to consider the provision of black start from non‑traditional generation technologies to facilitate the restoration of the future GB power system [6].

Aspects of security of supply also include the sufficient provision of ancillary services to stabilise power system operation. Ancillary services are not within the scope of our work, but a short commentary can be found in Appendix 12.2.

Scotland’s electricity system

Scotland’s electricity system operates as a part of the wider GB power system meaning electricity supply and demand must be always equal across the whole of GB. Generators anywhere in the GB power system can sell electricity to any demand, regardless of distances, through bilateral agreements and power exchange markets. It is then the responsibility of the energy system operator, National Grid ESO, to redispatch generation and demand to ensure that the physical electrical network can cope with the trades.

In the north of Scotland, the transmission and distribution network are operated and owned by Scottish & Southern Electricity Networks (SSEN). In the south of Scotland the transmission and distribution network are operated and owned by Scottish Power Transmission (SPT) and Scottish Power Energy Networks (SPEN) respectively. These transmission networks interface with the transmission network operated by National Grid Electricity Transmission which covers England and Wales, see Figure 2.

The boundary between Scotland and the rest of GB will be subject to future increased power transfer requirements due to additional onshore and offshore wind generation locating in Scotland. When there is low generation output in Scotland there may be power flowing from the rest of GB to Scotland to meet demand. However, these flows will be low compared to the flow from Scotland to the south so there is unlikely to be further requirements for network extension to support this on top of those for flows from Scotland.​ According to National Grids ETYS21 [7] there is currently a total of 6,100 MW transfer capability between Scotland and the rest of GB^[3].

Figure 2 Network infrastructure in 2022 across the B6 boundary [7]

Table 1 outlines the installed firm generation and the corresponding de-rated capacity in Scotland for the year 2021. Firm generation is defined here as generation types which can generate when required, and independently of external factors such as weather conditions. We also account for “de-rated” capacities where aspects such as outage rates are incorporated. Table 1 shows the de-rated firm generation and interconnector capacity in Scotland in 2021 was 8,489 MW while peak demand was 4,890 MW. Peak demand as a percentage of total firm de-rated capacity in Scotland was therefore 58%, meaning that there was secure installed firm capacity which is likely to meet demand in 2021. Therefore, the current generation mix in Scotland’s electricity system provides sufficient security of supply.

In the next sections, we will investigate scenarios for what the future electricity system in Scotland will look like and undertake more detailed analysis into how security of supply may evolve.

Table 1 Total and de-rated firm generation and interconnector capacity (MW) in Scotland in 2021 (see Appendix 12.13 for de-rating factors)

100% renewable electricity systems

Renewable electricity generation technologies can be split into two categories related to the challenges of accommodating them into power grid [8] [9]:

• Variable Renewable Energy (VRE): dependent on short-term weather conditions, and typically use invertors to interface to the grid, for example, wind and solar; and
• Non-VRE technologies: dispatchable generation using synchronous generators including hydro with reservoir, biomass, geothermal, and concentrating solar power with thermal storage.

For VRE, additional flexible technologies such as dispatchable generation and energy storage are required to compensate intermittency. For non-VRE generation, the timing and volume of production can be adjusted to follow demands and market developments.

In this work, a 100% renewable electricity system is defined as: a system that operates exclusively on renewable energy sources, such as wind, solar, hydro, geothermal, and bioenergy. It does not rely on non-renewable sources such as fossil fuels, nuclear energy, or other non-sustainable sources of energy. The renewable sources can be instantaneous outputs from renewable generation, discharged energy stored previously from renewable electricity, or even imported renewable electricity from connections with neighbouring systems. 100% renewable electricity system is technically achievable, and this section explores countries and regions where they exist. However, there are exponentially increasing costs to reach 100% [10] [11] [12].

Several national electricity systems in the world already operate with, or close to, 100% renewable electricity. Details can be found in Appendix 12.3. Further detail on national electricity systems with high shares of VRE generation (operating with less than 100% renewable energy) can be found in Appendix 12.4. Details of regional electricity systems operating with near to 100% renewable electricity can be found in Appendix 12.5.

Table 2 summarises key features in countries and regions with high share of renewables in power production. For countries already operating with (or very close to) 100% renewable electricity supply, the share of VRE is actually very low. For countries and regions with a high share of VRE generation, despite future 100% renewable electricity targets, fossil fuel dispatchable generation is still playing a major role to provide flexibility – either from gas and coal plants within its system or imported through connections.

Table 2 Comparison between counties and regions with high share of renewable power production (2020 data, see Appendices 12.3 – 12.5)

Renewable electricity in Scotland

In 2020, the generation of renewable electricity in Scotland was equivalent to 97.4% of its gross electricity consumption. However, as shown in Figure 3, fossil fuel generation accounted for 15.6% and nuclear for 16.9% of the total electricity consumption in Scotland.

Figure 3 Proportion of electricity consumption by fuel in Scotland 2022 [13]

Scotland also exchanges large quantities of electricity with England, Wales, and Northern Ireland, mainly exporting rather than importing. To achieve a reliable and resilient 100% renewable electricity system in Scotland will require a set of low-carbon solutions to fill the increasing gap of flexibility requirement when more renewables are set to connect but fossil fuel and nuclear generation are phased out.

Changes to electricity markets

The transition to a net zero energy system requires large-scale building of new power infrastructure. For example, upgraded and new transmission lines to meet increasing power demands; large onshore and offshore wind farms in remote areas; dispatchable power plants running on Hydrogen or fitted with carbon capture and storage (CCS) technology; and flexible technologies which can respond at different timescales to increasingly variability such as pumped hydro storage.

The need for reform is exemplified by curtailment costs in the UK doubling in just one year, from £145 million in 2019 to £282 million 2020 [14]. Well-designed electricity markets should efficiently incentivise capacity investment as well as dispatch of generation and network assets to facilitate the net zero transition.

Significant reforms of electricity markets in the UK are required to enable the transition to a net zero energy system at low cost while ensuring security of supply. Potential changes to electricity market arrangements were outlined in a consultation document on potential reforms published by BEIS in July 2022, ‘Review of electricity market arrangements’, referred to as REMA [15]. The aim of REMA is to establish the electricity market reform necessary for a fully decarbonised electricity system by 2035, which supports the transition to an economy-wide net zero energy system by 2050. The reforms are intended to form the final critical step towards supporting the net zero transition.

The main approaches outlined in REMA are reforming to a net zero wholesale market; markets suited to the roll out of mass low-carbon power; incentivising investment in flexibility technologies such as by introducing locational pricing; ensuring capacity adequacy; and reforming ancillary services which enable operability. There is significant debate around the advantages and disadvantages of these potential reform measures. These approaches and potential impacts on the Scottish electricity system are outlined below. More background information on these reforms can be found in Appendix 12.6.

Technology development in Scotland to 2045

Scotland pathway using FES22

We use National Grid’s FES [3] as the baseline for technology development in Scotland to 2045. Based on FES pathways, we extracted and scrutinised data specifically for Scotland. FES is external to the Scottish Government and takes a UK-wide approach and may not necessarily be consistent with Scotland’s annual emission targets. However, it has a high level of detail including a regional breakdown which means that Scotland specific data can be extracted. We modelled metrics that provide a measure of security of supply and investigate this with an extended set of stress tests applied.

Four scenarios are presented in FES with three pathways meeting net zero targets and one pathway that falls short (see Appendix 12.7). This report uses the System Transformation scenario as the baseline for installed firm generation capacity, installed VRE generation capacity, peak demand, installed storage capacity, network connection to England and Wales and interconnectors to Northern Ireland and Norway. The System Transmission scenario was chosen because it represents a middle-ground in terms of the expansion of technologies compared to the Leading the Way and Falling Short scenarios. It is recognised that the System Transformation scenario is not aligned with Scottish Government policy with a high usage of hydrogen for heating. The following modifications were made to the System Transformation scenario:

1. Offshore wind installed capacity by 2030 was changed from 7,000MW to 9,500 MW in line with Scottish Government targets.
2. Interconnector capacity was extended from solely the 500 MW Moyle interconnector to this plus 700 MW interconnection to Norway (1200 MW overall) from 2035 which is in line with the Consumer Transformation scenario.

We used the PyPSA-GB model of the electrical power system for modelling FES data and for calculating power flow, see [16] and Appendix 12.9 for more details. Data is included for the years 2021, 2030, 2035, 2040, and 2045.

Installed firm generation

Figure 4 shows the installed firm generation capacity in Scotland for the System Transformation scenario.

• The last remaining nuclear power station in Scotland, Torness, closes in 2028.
• The existing Peterhead Combined Cycle Gas Turbine (CCGT) power plant is assumed to close in 2026 and open as Peterhead 2 with reduced capacity (1,200 MW CCGT to 910 MW CCGT + CCS) in 2027. The CCS Gas generation capacity is then doubled between 2040 and 2045 to 1,800 MW.
• Hydrogen powered generation capacity is also added with 690 MW by 2040 and 1,924 MW by 2045.
• Hydro power plants see moderate increases out to 2045.
• Significant increases in biomass generation capacity to around 1,900 MW in 2045.
• 

Figure 4 Installed firm generation capacity (GW) in Scotland under the System Transformation scenario

Installed variable renewable generation

Figure 5 shows the installed VRE generation capacity in Scotland for the System Transformation scenario.

Figure 5 Installed VRE generation capacity (GW) in Scotland under the System Transformation scenario. Offshore wind in 2030 has been changed to 9.5 GW to reflect Scottish Government ambitions of 8-11 GW

• Solar Photovoltaics capacity consistently grows from 462 MW in 2021 to almost 4,000 MW in 2045.
• Wind offshore is projected to grow from 1,700 MW in 2021 to 33,900 MW in 2045. The Scottish Government ambitions for 8,000-11,000 MW of offshore wind capacity by 2030 is not met in the System Transformation scenario. We modified the scenario to meet this target by inserting an installed capacity of 9,500 MW for offshore wind by 2030, in order to test the system under the conditions that this target is achieved.
• Wind onshore is projected to grow from 8,900 MW in 2021 to 23,900 MW in 2045.

Installed storage capacity

Figure 6 Installed storage capacity in Scotland under the System Transformation scenario.

• Pumped storage hydroelectric installed capacity forms the majority of installed storage capacity in Scotland in 2021. It is projected to rise to above 2,000 MW by 2040. There are several potential pumped storage projects in the pipeline: Coire Glas 1,500 MW [17], Red John 450 MW [18], and Corrievarkie 600 MW [19].
• Battery storage is projected to increase substantially from 124 MW in 2021 to 1,800 MW in 2030, followed by more modest growth to 2,100 MW by 2045.
• Compressed air energy storage (CAES) and liquid air energy storage (LAES) are also projected to have increasing capacity from 0.9 MW of CAES and 1.4 MW of LAES in 2021 to 1,100 MW of CAES and 553 MW of LAES in 2045.

The timescale of usage of these electrical storage types is constrained by the time it takes for each technology to fully discharge at full power. Batteries in FES are assumed to be suited to intra-day charging/discharging cycles. Pumped storage, CAES, and LAES are assumed to be capable of charging or discharging at maximum output for a longer period of time. These storage types are suited to system balancing on seconds, hours, and days timescales but these, bar pumped storage, are unlikely to be used for long-duration storage where balancing is required on weeks and months timescales due to a prolonged period of low VRE output. The FES scenarios mainly rely on hydrogen as a storage medium for these longer timescales.

Peak demand

Figure 7 shows the projected peak electricity demand in Scotland under the System Transformation scenario. There is a steady increase in peak demand from 4,600 MW^[7] in 2021 to 8,700 MW in 2045.

Figure 7 Peak electrical demand during GB-wide average cold spell in Scotland under the System Transformation scenario.

The System Transformation scenario assumes that most heating is met by Hydrogen^[8] (see Appendix 12.8), which results in a lower peak demand than in Consumer Transformation (heating is primarily electrified). The Consumer Transformation peak electricity demand for Scotland in 2045 is 11,300 MW due to most heating being met by electrification through heat pumps. This peak is 2,600 MW higher than the System Transformation assumption.

The peak demand shown here does not include electrical demand from electrolysers producing hydrogen. FES analysis assumes that electrolysers can be turned off during peak demand, and therefore, do not need to be included in calculations for security of supply metrics. However, our analysis does include this demand for power flow analysis and import and export calculations.

Transfer capability and interconnectors

The only interconnector from Scotland to outside GB is currently the Moyle interconnector to Northern Ireland. The Moyle interconnector was limited in transfer capability to 160 MW in 2021, but from 2022 has increased to its full capacity of 500 MW. We used the Consumer Transformation projections for interconnection expansion which includes a 700 MW connection to Norway by 2035 in addition to the 500 MW Moyle interconnector. This modification was made to ensure the baseline includes a higher interconnection for Scotland, and then a stress test on the unavailability of interconnectors could explore the impact on security of supply of no connection with Northern Ireland and Norway.

Transfer capability across the B6 boundary is projected to increase about four-fold from 6,100 MW in 2021 to 24,700 MW in 2040 for the System Transformation scenario. This increase is to enable power flow from the increased wind generation in Scotland to the rest of GB. Power flow to Scotland will be lower than from Scotland, so does not affect the transfer capability requirements. This scenario projection is substantially higher than increases in the Network Options Assessment (NOA) due to higher projections for installed capacity of renewable generation in Scotland. National Grid’s Electricity Ten Year Statement [7] includes more details on the future boundary transfer capability requirements for the B6 boundary which connects Scotland’s transmission network to the rest of GB.

Measuring security of supply

This report focuses on capacity adequacy as a measure of security of supply, which ensures that we always have enough energy to meet our needs. National Grid ESO publish capacity adequacy analysis for the GB system, often in its winter outlooks and FES reports. Given the scope of this work, a similar standard approach is used, with a focus on the Scotland system. The interaction with the rest of the GB system is modelled as flow across the boundaries.

The GB standard for generation adequacy uses the Loss of Load Expectation (LOLE) as the indicator of supply reliability, complemented by other relevant risk metrics which are detailed in Appendix 12.10. LOLE is defined as the expected number of hours over a period in which supply resources are insufficient to meet demand. It provides a measure of security of supply over a statistically long-term period, such as a year. The current reliability standard for LOLE in GB is set to no more than three hours in a year.

De-rated system margin is used as a proxy for risk of loss of supply. It is more useful as a measure of security of supply than installed capacity, as it accounts for the probability of a forced outage.

Security of supply metrics for System Transformation

De-rated system margin

An overview of the forecasted de-rated margin for Scottish system in the System Transformation scenario is shown in Figure 8. While peak demand sees steady growth, it is exceeded by the increase in available firm capacity (including the equivalent firm capacity of VRE) that can serve peak demand with high probability.

Figure 8 of de-rated supply capacity, peak demand and supply margin of Scotland for System Transformation from 2025 – 2045

The de-rated system margin increases from 2,200 MW in 2025 up to 12,200 MW in 2045. The capacity of wind shown in Figure 8 are de-rated using equivalent firm capacity factors (ranging between 13-17% in recent NG reports [20] [21] [22]). This represents the wind generators contribution to security of supply at stress events. Due to the significant amount of onshore and offshore wind added into the system, from 2035 onwards the de-rated wind capacity alone is higher than the peak demand. This ensures a very high level of de-rated system margin.

The GB supply margin under System Transformation can be found in Appendix 12.11.

Loss of load expectation

Figure 9 LOLE results for System Transformation in Scotland from 2021 – 2045

In line with the high de-rated system margin the calculated LOLE of Scotland’s electrical system stays at a very low level for the System Transformation scenario in all modelled years. The lower the LOLE number, the lower the risk of insufficient generation to meet demand. From our results, the LOLE increases marginally from 0.020 hours per year in 2025 to 0.023 in 2030. The increase is due to the anticipated closure of nuclear power stations over the 5-year period. This is still significantly below the 3 hours currently allowed in the GB reliability standard. The rise in LOLE between 2025 and 2030 could be higher but the addition of 7,870 MW wind capacity during this period helps to mitigate the effects of phasing out nuclear generation.

LOLE values from 2035 onwards are less than 0.0001, and so low that statistically the loss of load can be considered highly unlikely. This very low LOLE from 2035 is attributed to the significant influx of new electricity generation of various types in the Scottish system in the System Transformation scenario, e.g., Scotland’s wind capacity is projected to increase by over 25,000 MW, reaching 49,400 MW in 2035^[9], the largest increase over a 5-year period in the scenario. Even with an Equivalent Firm Capacity (EPC) factor of 16.1%, wind energy alone is enough to provide reliable generation equivalent to 8,400 MW, enough to meet Scotland’s peak demand of 6,000 MW in 2035. The addition of biomass, Hydrogen, and pumped storage capacity from 1,223 MW in 2035 to 4,648 MW in 2040 significantly increases the dispatchable electricity sources in Scotland. This also exceeds the Scottish demand growth (1,500 MW) during that period, further enhancing supply security.

In practice, the actual target LOLE for the GB system operator has been less than 3 hours. The LOLE reported in National Grid’s Winter Outlook in 2021 and 2022 was 0.3 and 0.2 hrs/year for the GB system. The Scottish electrical system is modelled to have a lower LOLE than the GB system. In 2021 the Scottish LOLE was modelled as 0.108 hrs/year and this is expected to further decrease in the future.

Power dispatch

Power dispatch is the cost-optimised mechanism by which power needs and demands are balanced. Power dispatch modelling can be used to illustrate security of supply by demonstrating how generation and storage are being used to meet demand. Power dispatch modelling outputs are for the same 2-day peak period in 2045^[10]. Interconnectors are included in the power flow calculation but excluded from modelled output figures to provide focus on the role of generators and storage.

Figure 10 shows the power dispatch of the Scottish electricity system for generation, storage, and export at the B6 boundary (where Scotland connects with the rest of GB) for the System Transformation scenario. Offshore and onshore wind power dominate generation, and there are large power export flows across the B6 boundary to the rest of GB. Storage technologies and biomass are dispatched, while exports continue to the rest of GB, during this high demand period. The equivalent power dispatch at the same peak period for GB^[11] can be found in Appendix 12.11.

Figure 10 Power dispatch of Scotland for System Transformation in 2045 over 2-day peak period.

Imports and exports

Scotland supports the overall GB system with net exports of power across the B6 boundary. Figure 11 and Figure 12 show the monthly import (from rest of GB to Scotland) and exports (from Scotland to rest of GB) across the B6 boundary. Outputs were obtained by running the model with historical data for 2021 and the System Transformation scenario for 2045. Scotland is a net exporter to the rest of GB and exports will increase in future^[12]. There will also be an increase in the level of import from the rest of GB to Scotland which could be due to increased demand coupled with increased reliance on intermittent power generation. The level of import and export have a seasonal pattern, with higher imports in the summer and higher exports in the winter. This is due to higher wind generation and demand in winter than in summer which results in more opportunities to export to the rest of GB.

Figure 11 B6 monthly import in 2021 and 2045 under the System Transformation scenario

Figure 12 B6 monthly export in 2021 and 2045 under the System Transformation scenario

Stress testing Scotland’s security of supply

Our modelling has shown that Scotland’s electricity system has a low probability of being unable to meet demand in the modelled years. However, the assumptions are based on a particular set of conditions and do not account for the full range of possible situations. Stress tests were used to test the security of supply of the Scottish electricity system beyond the original scenario conditions (Figure 13).

Figure 13 Network map of Scotland and stress tests scenarios

These are summarised relative to the System Transformation scenario base case in Table 3.

Table 3 Summary of assumptions used in stress testing scenarios

We investigate the power flow for each of the stress tests and the security of supply metrics up to 2045. We also analyse the impact on imports and exports from/to Scotland. All stress tests are applied for 3 days either side of peak demand. All the stress events are applied to the base case independently, and are assumed to last the whole week in which the peak demand occurs.

Security of supply for the stress tests

Full outputs from stress tests can be found in Appendix 12.12. Figure 14 summarises the LOLE for all the stress test cases. During peak demand periods, the impact of unavailability of supply are higher than other times of the year. The LOLE for all stress tests is within the three hours/year reliability standard, and are below the modelled 2021 Scottish LOLE of 0.108 hrs/year, except for B6 failure in 2025 and 2030 and interconnector failure in 2030. The system from 2035 onwards is very secure with a low LOLE.

In 2025 and 2030 the stress test of disconnection with the rest of GB has the highest impact on the security of supply as measured by LOLE, followed by unavailable interconnectors and gas supply issues. This implies that the reliance of import from the rest of GB in maintaining the capacity adequacy in Scotland is more than the other supply types. However, its significance becomes negligible from 2035 due to a large increase in offshore wind capacity in the Scottish system and additional capacity from battery storage, pumped hydro, Hydrogen power plant, and biomass in subsequent years.

(a)

(b)

Figure 14 (a) LOLE for Scotland in the stress test cases (2025–2045); (b) GB 3h/yr limit added for comparison

Import and export for the stress tests

The stress tests have impacts on the imports and exports across the B6 boundary between Scotland and the rest of GB. Countries in Europe increasingly exchange power with each other, particularly to share cheap abundant electricity, as has been the case historically with France exporting nuclear power to central Europe and Denmark exporting wind power to Norway who can store this in their large pumped hydro schemes. Scotland shares an electricity market with the rest of GB but imports and exports are a useful measure of the dependence on the power exchange across the B6 boundary.

Figure 15 shows for each stress test the total import and export across the B6 boundary over the 6-day period the stress tests are applied, including the peak GB demand period in the middle of the 6 days. The base case in 2045 sees increases in imports due to closure of Torness nuclear power plant and reduced capacity of Peterhead.

Figure 15 Import and export for the stress tests across the B6 boundary

The stress tests for offshore wind farm failures, gas power generation in Scotland unavailability, battery failures, and interconnector issues result in increased imports into Scotland. The low VRES output stress test sees Scotland become a net importer over the 6-day period modelled. The following findings are identified:

• Offshore wind farm failures reduce total wind generation over the period resulting in higher imports and lower exports.
• The low VRES period reduces total wind generation by a greater degree than the offshore wind farm failure meaning that there are more imports than exports.
• Gas supply issues reduce the capability of Scotland to provide firm generation over the 6-day period, resulting in more periods where imports from the rest of GB are required, typically when there is low wind generation. This has minimal impact on imports and exports during the modelled period.
• Battery failure decreases the ability of the system to store excess renewable power generation to be utilised later during low VRES periods. This has minimal impact on imports and exports during the modelled period.
• Interconnector issues reduces exports of excess wind generation to Norway or Northern Ireland, at the same time as reducing imports from these countries to meet demand when there are higher electricity prices in Scotland. The result is slightly increased imports, and increased exports which are exported to the rest of GB rather than to Norway or NI.

Overall, the low VRES output period has the largest impact on imports and exports from/to Scotland, followed by the offshore wind farm failures. This highlights the importance of wind power generation in the future Scotland electricity system. Interconnectors to NI and Norway have the next biggest impact, but this will likely be more impactful under other FES scenarios which see larger increases in interconnector capacity. The battery failure and gas supply issues have minimal impact on the imports and exports in the modelled period.

Self-sufficient Scotland

In this section we assess the impacts of Scotland having an entirely self-sufficient future electrical system. We modified our original model (Table 3) to consider Scotland as an isolated electrical network in the self-sufficient base case. All interconnections to Northern Ireland and Norway and all transmission links to the rest of GB across B6 were removed. After calculating the LOLE in this new base case, we conducted a stress test. We also stress test with low VRES power^[13] and examine the additional capacity required to reduce LOLE to the 3-hour GB reliability standard.

Figure 16 LOLE of self-sufficient Scotland system in base case, low renewable output stress case and with additional firm capacities

The changes in level of capacity adequacy for a self-sufficient Scotland is given in Figure 16. Violation of the 3 hours GB standard occurs in the base case in the years 2025 and 2030, but the LOLE is less than 0.18 hours in 2035 and decreases in the following years. Figure 16 also shows the additional firm capacity needed to reduce the LOLE in 2030 to within the minimum required 3 hours, and to a more conservative range, for example, the 0.3 hours reported in the 2022 Winter Outlook^[14].

To achieve LOLE of 3 or 0.3 hours an additional 250 MW or 1000 MW equivalent firm capacity is needed respectively. Several alternative supply types can each provide an equivalent (de-rated) 250 MW of additional firm capacity:

• 274 MW installed capacity of CCGT with CSS.
• 380 MW battery storage 3 hours storage duration of 1140 MWh.
• 1,553 MW of installed capacity of offshore wind.

For 1000 MW additional firm capacity:

• 1,095 MW installed capacity of CCGT with CCS.
• 1,510 MW battery storage with 3 hours storage duration of 4,530 MWh.
• 6,211 MW of installed capacity of offshore wind.

The increase in offshore wind capacity in the base case is much higher than the additional installed capacity of wind required above. Therefore, as shown in Figure 17, the LOLE in 2035 is well within the acceptable range.

In a self-sufficient Scotland the share of wind in the total supply mix becomes more significant. Under the low VRES power output stress test, the LOLE increases to 6.8 hours in 2025 and 5.6 in 2030 but decreases to 0.32 hours in 2035 and reduces further in 2040 and 2045. The low LOLE in 2035 is due to a 25,000 MW increase in installed wind capacity from 2030.

Even after scaling down to 20% of VRES potential power output, there is still enough contribution from wind generation to serve the peak demand. Increases in biomass, hydrogen, and pumped storage capacity in 2040 and 2050 make non-variable supply alone sufficient to meet peak demand, further reducing the LOLE in the later years under the low VRES stress case. With 400 MW additional firm capacity can bring the LOLE to within 3 hours in 2025 and 2030. This is 150 MW more than is needed in the self-sufficient base case.

Black start capability

Removing interconnections and links to England may result in the loss of access to generators that are capable of providing black start. However, it does not necessarily imply that the black start capacity in Scotland is insufficient. The System Transformation scenario projects a significant increase in the capacity of hydro, battery storage, and pump-hydro storage in Scotland, which offer good black start capabilities. These sources have a combined capacity of 4,368 MW in 2030, which will increase to 6,023 MW in 2045, accounting for more than half of peak demand. Whether these assets are sufficient for black start depends on conducting simulations or tests of the system under various scenarios. It is also crucial to regularly review and update the black start procedures to ensure that they remain effective and relevant.

Low capacity and high demand scenario

We further tested the system, modifying the base case (System Transformation) scenario by removing future thermal power plants (i.e., hydrogen, gas and biomass CCS); using the more conservative ETYS21 [7] assumptions on B6 boundary expansion; and increasing peak demand to those in the Consumer Transformation Scenario. Table 4 shows the resulting modifications to the base case (see Appendix 12.18 for full dataset). We then show results for the de-rated system margin, LOLE, stress tests, and imports and exports.

Table 4 Modifications to System Transformation Base Case for the low capacity and high demand scenario
(Base Case capacities in brackets)

De-rated system margin

In the low capacity and high demand scenario, the de-rated system margin increases from 1,400 MW in 2025 to 4,500 MW in 2045, with a decrease in 2030 due to the assumed closure of all gas and nuclear generation in Scotland between 2025 and 2030. In the base case scenario, the gas CCS generation would have provided an additional de-rated capacity of approximately 1,600 MW in 2045.

The de-rated margin as a percentage of peak demand under the low capacity and high demand scenario between 2025 and 2045 is on average 32%. This is lower than the average 90% under the original base case scenario.

Figure 17 Installed firm generation capacity (GW) in Scotland under the low capacity and high demand scenario.

Loss of load expectation

Figure 18 LOLE results for low capacity and high demand scenario in Scotland from 2021 – 2045. GB Reliability standard 3hrs/y

The LOLE of the low capacity and high demand scenario, as illustrated in Figure 18, is considerably higher than the base case scenario (Figure 9) in all future years.

The year 2030 shows a significant increase in LOLE due to the closure of all gas and nuclear power stations, resulting in a LOLE of 6.3 hours/year which is higher than the GB reliability standard of 3 hours/year. Potential options for addressing this include keeping gas generation running for additional years while waiting for further renewable generation deployment or incentivising the development of additional storage and renewable generation before 2030.

By 2035 the subsequent strong growth of renewable generation capacity brings the LOLE back below the GB reliability standard. This is particularly due to an additional offshore capacity of approximately 17,300 MW from 2030 to 2035. As wind generation and storage capacity continue to increase, LOLE drops further from 2 hours in 2035 to 1.2 hours in 2045.

The lowest LOLE in the low capacity and high demand scenario is 1.2 hours/year in 2045, while in the original base case scenario, it is 0.0001 hours/year. This difference can be attributed to the exclusion of natural gas, hydrogen, and biomass, as well as higher demand. LOLE after 2030 in the low capacity and high demand scenario is relatively high compared to historical Scottish LOLE, such as 0.108 hrs/year in 2021. While this shows an increased risk of interruption to supply, it does not necessarily imply that such a shortage event will occur as it is still below the GB reliability standard.

Security of supply for the stress tests

Figure 19 LOLE for Scotland in the stress test cases under the low capacity and high demand scenario (2025–2045). GB Reliability standard 3hrs/y. LOLE 0.108 hrs/y of 2021 Scottish system

Except for the year of 2030 and the case of B6 failure in 2030-2045, all stress tests are within the GB reliability standard of three hours per year, but still greatly exceed the historical Scottish and GB LOLE in 2021, as presented in Figure 19. The disconnection from the rest of the GB stress test as illustrated using the ‘B6 Failure’ case has the most significant impact on the security of supply as measured by LOLE, far more than other test cases. LOLE of the other stress test cases are not significantly different from each other, with the offshore wind farm failure test highest, followed by unavailable interconnectors. This suggests that maintaining capacity adequacy in Scotland is highly dependent on imports from the rest of GB in this scenario.

The role of the B6 connecting Scotland to the rest of GB is more significant for security of supply in the low capacity and high demand scenario compared to the base case (System Transformation) scenario. The import capacity capability to Scotland across the B6 boundary is the main supply source after the renewable generation capacity in Scotland. In contrast, in the base case scenario, there is considerable capacity of CCS gas, biomass, and hydrogen generation, along with the B6 import capability, which can contribute to the security of supply.

Imports and exports

Imports (from rest of GB to Scotland) are higher and exports (from Scotland to rest of GB) are lower for the low capacity and high demand scenario compared to the base case scenario. This trend is consistent to 2045, which is shown in Figure 20 for imports and Figure 21 for exports. Over the year both scenarios have net exports of power across the B6 boundary. These results are due to the decreased generation and B6 boundary transfer capacity, and further highlight the greater importance of the B6 boundary in the low capacity and high demand scenario for security of supply.

Figure 20 B6 monthly import in 2045 under the base case and low capacity and high demand scenario

Figure 21 B6 monthly export in 2045 under the base case and low capacity and high demand scenario

Figure 22 shows the import and exports for the stress tests for the low capacity and high demand scenario. There is a reduced level of exports in these stress periods compared to the System Transformation base case, due to the lower generation capacity from hydrogen, gas CCS, and biomass. The greater reliance on VRES and the B6 boundary is highlighted by the high levels of import required for the low RES output stress test.

Figure 22 Import and exports in 2045 for 6-day period for stress tests in low capacity and high demand scenario

Conclusions

Lessons learned from national and regional electricity systems operating with close to 100% renewable energy sources:

• Several national and regional electricity systems operate at, or close to, 100% renewable electricity. However, these countries typically rely on dispatchable (non-VRE) renewable sources such as hydropower and storage reservoirs to generate and store electricity. These dispatchable renewable resources are only available at the required scale in a few countries. In Scotland, the most available renewable resource is wind, which is a variable source of energy.
• There are fewer examples of national electricity systems that operate with a high proportion of variable wind and solar energy shares. Denmark has the highest overall share of renewable electricity at 84%, with a high proportion from variable renewable sources and wind at 60% of total electricity production.
• Scotland has high wind generation, which makes up around 49% of total electricity generation, and relies on imports and exports with the rest of GB. It is most closely comparable to Denmark, which also makes extensive use of connection to neighbouring countries.

Changes to electricity market arrangements:

• Current GB electricity market arrangements are not suited to the net zero transition and potential reforms have been set out, which can enable a fully decarbonised electricity system by 2035. It is too early in the process to see a path for which reforms will be implemented and specify the impact they will have on security of supply.
• Splitting the wholesale market could improve the long-term sustainability of investing in renewable power in Scotland. However, it is possible that other reform proposals can provide the benefits outlined, and there could be a lack of additionality.
• Locational pricing might have the impact of depressing prices received by generators in Scotland as locational prices could be higher in England than in Scotland. Wind farms may require additional subsidy to be built in Scotland under locational pricing.
• A potential enhanced capacity market should take account of the issues specific to Scotland, while the Scottish Government should be an important stakeholder in strategic reserve decisions.

Technology pathway to net zero in Scotland in 2045:

• We have analysed the technology pathway according to the System Transformation scenario out to 2045 for Scotland. We found that security of supply metrics for Scotland in this scenario is well within the current GB reliability standards and comparable to current levels.
• There will be a reduction in traditional firm generation capacities (no nuclear and CCGT power plant generation capacity reduced when changing to CCS technology). However, these losses are offset by vast increases in wind and solar installed capacity, which can still provide security of supply, as well as increasing low-carbon firm generation capacity in the form of biomass, hydrogen and CCGT, with CCS power plants closer to 2045. Security of supply is further enhanced by the installation of battery, pumped hydro, liquid air and compressed air energy storage.
• Peak demand in Scotland is expected to rise to around 9,000 MW by 2045 but the de-rated system margin still increases from 2,200 MW in 2025 up to 12,200 MW in 2045, which shows there is sufficient firm generation. This was further verified by power dispatch simulation.
• The future Scottish electricity system has security of supply under the System Transformation scenario, but this cannot be directly assumed for the rest of GB supply and demand will likely continue to be balanced at GB-level by National Grid as the energy system operator. Therefore, while the generation capacity in Scotland may seem excessive in the context of security of supply, it will be utilised to decarbonise the rest of GB’s electrical system.
• We have further tested the future Scottish electricity system by modifying the System Transformation scenario: removing future thermal power plants; using more conservative B6 boundary expansion assumptions; and increasing peak demand. In this low capacity and high demand scenario security of supply in 2030 is worse (LOLE of 6.3 hours/year) than the GB reliability standard (LOLE of 3 hours/year).
• Beyond 2030 security of supply increases in the low capacity and high demand scenario but is relatively high compared to historical Scottish security of supply.
• Except for the year of 2030 and B6 failure in 2030-2045, all stress tests are within the GB reliability standard of three hours per year, but still greatly exceed the historical Scottish and GB security of supply in 2021.

Imports and exports between Scotland and the rest of GB:

• The System Transformation scenario requires a four-fold increase in transfer capability between Scotland and the rest of GB, from 6,100 MW in 2021 to 24,700 MW in 2045.
• Scotland will continue to be a net exporter to the rest of GB, and both total and net exports will increase. There are periods when Scotland will import only because it is economic to do so, rather than due to lack of local supply. There will be an increase in the level of import from the rest of GB due to increased demand coupled with the increased reliance on wind power generation.
• A period of low wind and solar generation has the largest impact on imports and exports from/to Scotland, followed by offshore wind farm failures. This highlights the importance of wind power generation in the future Scotland electricity system.
• Problems with interconnectors to Northern Ireland and Norway have the next biggest impact, but this will likely be more impactful if we see larger increases in interconnector capacity. Battery failure and gas supply issues have minimal impact on the imports and exports in the modelled period.
• Imports from rest of GB to Scotland are higher and exports from Scotland to rest of GB are lower for the low capacity and high demand scenario than for the System Transformation scenario. High levels of import are required for the low RES output stress test, illustrating the greater reliance on VRES and the B6 boundary in this scenario.

A self-sufficient Scotland:

• A self-sufficient Scotland with no connection to the rest of GB and no interconnector capacity to Northern Ireland or Norway was found to violate the 3 hours GB reliability standard in the years 2025 and 2030. However, by 2035 the reliability is within historical values and decreases in the following years.
• We find 250 MW and 1000 MW of additional equivalent firm capacity is needed in 2025 and 2030 to meet the reliability standard of 3 hours or recent values of 0.3 hours respectively. This can be achieved with the addition of 1,553 MW (to meet 3 hours) and 6,211 MW (to meet 0.3 hour) of installed capacity of offshore wind.
• The projected system beyond 2040 can meet reliability standards even after scaling down wind and solar generation to 20% of its potential output around the peak demand period. 400 MW additional equivalent firm capacity can bring the reliability standard to within 3 hours in 2025 and 2030, which is only 150 MW more than is needed in the self-sufficient System Transformation base case.

References

Appendices

2022/23 Winter Outlook

The 2022/23 winter outlook was developed amid unprecedented volatility in energy markets and concerns around shortfalls in gas supply. Additional scenarios were added to explore the potential impact of reductions in available electrical capacity from gas power plants and import capability through interconnectors. The National Grid report found that under the base case that there will be adequate security of supply with a de-rated margin of 3,700 MW (6.3%) in GB system which is in line with recent years (see Figure 23).

Two additional scenarios were presented in the 2022/23 winter outlook: 1) no electrical imports from continental Europe (Ireland and Norway interconnectors remained available); and 2) in addition to this, 10GW of CCGT being unavailable. Scenario 2 led to security of supply concerns and as a result 2GW of coal power plants and a 2GW novel demand flexibility service were brought into contingency planning.

Figure 23 De-rated margins from National Grid’s recent Winter Outlooks showing the figures for the Winter Outlook 22/23 are in line with historical margins

Ancillary services and system operability

Ancillary services are essential for ensuring the stability and reliability of power system operations, as they maintain frequency and voltage within acceptable ranges and prevent disruptions and blackouts. Unlike fossil-fuel generators, wind turbines and PV panels don’t provide the same level of inertia required to stabilise the system frequency changes following a loss of generation or demand. Ancillary services are not within the scope of the report but are important in understanding the impact of the changing electricity mix on power system operability. To compensate for the lack of inertia in renewable energy sources, modern wind turbines can be equipped with power electronics and control systems that provide synthetic or virtual inertia to the grid. Energy storage systems and other advanced grid technologies can also help balance the system and maintain stability.

National electricity systems with near 100% renewable

Several national electricity systems in the world already operate with, or close to, 100% renewable electricity. For example, Iceland generates all its electricity from either geothermal or hydropower. Other countries with high share of renewable generation include Paraguay (99%), Norway (98%), Uruguay (95%), and Costa Rica (93%) [23] [24]. Despite these impressive levels of renewable generation, there is still some non-renewable electricity generation in each of these countries. In Paraguay, small-scale industrial power plants using sources such as oil, natural gas, and coal contribute to the non-renewable part. In Norway, thermal power plants are the primary source of non-renewable electricity. Both Uruguay and Costa Rica rely on oil-fuelled power plants to support renewables.

The common feature of these countries is that generation from hydropower plants and storage reservoirs dominates the renewable supply. In Norway, many hydropower plants have storage reservoirs. With reservoirs, hydropower production can be adjusted within the constraints set by the watercourse itself. Therefore, they have flexibility which makes it possible to follow the variation of demands, even during periods when there is little rainfall or river inflow.

Blåsjø, Norway’s largest reservoir, has a capacity of 7.8 TWh^[15], which is equivalent to three years’ normal river inflow, and can store water for a long period to meet high electricity demand during the heating season in winter or support electricity supply in a dry year [25]. In addition, other hydropower plants with small reservoirs offer short-term flexibility, and can be operated to provide both baseload and peak load due to their ability to be shut down and started up at short notice. Overall, these reservoir storages help to smooth out production over days, weeks, months or between years.

Reservoirs also make it possible to manage output to maximise income through both export and import power to or from neighbouring countries when there is a price difference. Electricity is exchanged with Sweden, Denmark, and Finland through an integrated market called Nord Pool, which is in turn connected to the wider European market through interconnectors to the UK, Netherlands, Germany, the Baltic states, Poland, and Russia

More than 75% of Norway’s renewable generation is dispatchable [26], which ensures the electricity system operates with high levels of reliability and security.

Electricity systems with very high VRE share

The leading national electricity systems with high shares of wind generation (VRE) are Denmark (56% of total electricity production from wind in 2020), Uruguay (40%), Lithuania (36%), Ireland (35%), the UK (24%), Portugal and Germany (both around 23%). For solar energy, the top countries are Honduras (12.9%), Australia (10.7%) and Germany (9.7%) [23] [24] [26].

Countries which rely on VRE have lower overall shares of renewable electricity than countries that benefit from abundant hydropower resources. Of the countries with high VRE share, Denmark has the highest overall share of non-fossil fuel generation at 84%, including 20% from biofuel electricity which is mainly produced in CHPs, and 4% from Solar PV. Since biofuel CHP can be dispatchable, it provides valuable flexibility in helping the operation of the Danish system with over 50% VRE.

The Danish Energy Agency has summarized the successful measures it has implemented to increase the share of variable renewable energy (VRE) while maintaining high security of supply over the past two decades. During this time, various technical and institutional solutions were introduced, as shown Figure 24:

• 2000-2009 (VRE shares <20%): Limited investments in flexibility were made, but the supply was met through more flexible operation of existing thermal power plants and better utilization of interconnectors. Flexible thermal power plants, interconnectors, and forecasting and scheduling systems were the primary sources of flexibility.
• 2010-2015 (VRE shares 20-44%): As the VRE share grew, larger investments in flexibility were made. Solutions included complete turbine bypass, electric boilers, heat pumps, and joining the Nordic power exchange for cross-border trading. The ability for VRE to self-balance was improved through the European cross-border intraday market.
• 2016-2020 (VRE shares 44-50%) and beyond: The focus shifted towards demand-side flexibility and increased sector coupling. Aggregators were introduced to encourage active consumer participation in balancing the system, and the market remained the main driver of flexibility.

The importance of different categories of power system flexibility in Figure 24 has varied over time for integrating renewables in Denmark. The generation side was the main source of flexibility until 2020, but these measures alone will not be able to accommodate the increasing amounts of VRE economically or technically. To continuously develop towards a 100% renewable Danish power system by 2030, Denmark sees increased sector coupling and demand-side flexibility as key providers of new flexibility measures in the future [27]. The focus of sector coupling has also changed from power and heating generation to using surplus electricity and decarbonizing difficult to electrify sectors.

Figure 24 Flexibility measures being implemented in different periods in Denmark power system. Note this indicates where new efforts are being focussed – e.g., interconnectors are still widely used after 2020

Regional electricity systems with near 100% renewable

In some countries, annual renewable energy production from certain regions is already reaching or exceeding local demand, e.g., Mecklenburg-Vorpommern, Schleswig-Hostein in Germany, Orkney in Scotland, and Samsø in Denmark.

The challenge Orkney faces is an interesting example of a regional electricity system with more than 100% VRE. Despite the excessive locally generated green energy (more than 130% over its local annual electricity demand), there are still periods when the wind speed is low, and Orkney needs to import electricity from the UK mainland. To find a non-fossil fuel based solution to tackle the issue of intermittency, a recent smart grid demonstration project – ReFLEX (Responsive Flexibility) Orkney [28] – has set the aim of fully decarbonising Orkney by 2030 through deploying smart controlled battery systems and electric vehicles, and enhancing demand response by interlinking electricity, heat and transport assets.

Background on proposals in REMA

Current arrangements

Under current electricity market arrangements electricity is traded through bilateral long-term contracts, and short-term power exchange marketplaces. Generators sell electricity to end-users often through energy retailers. Generators and suppliers then declare how much electricity they are expecting to generate or use to NG ESO. Based on these declarations a national electricity price is formed which informs power exchange markets on the prices to sell electricity in the short-term. This national price formation is often what is referred to as the wholesale price.

Generators and end-users are free to trade anywhere across Great Britain. For example, a wind farm in the north of Scotland can sell its generated electricity to an industrial end-user in London as easily as it can sell to supply the houses in a nearby town. However, these trades do not account for spatial considerations such as limits in the transmission network. Generators and demands must inform National Grid of their actions on a half-hour basis, where the balancing mechanism is used to ensure balance between supply and end-users. The balancing mechanism may ask generators to increase or reduce, and/or end-users to reduce, in return for additional payments. National Grid also procure additional services in ancillary markets to ensure safe and reliable operation of the grid. There are increasing costs to use the balancing mechanism as the proportion of renewables increases (Figure 25). This is a driving factor in the need for new market arrangements.

Figure 25 Left hand graph shows rising costs of curtailment of wind farms. Right hand graph shows points which represent the years from 2010 to 2020 relating to wind generation and annual cost, in addition to lines which plot out the cost of curtailment per MWh of wind energy produced. The points are rising through the years from £1/MWh to above £4/MWh showing that the cost of each MWh of curtailment is increasing.

Splitting the wholesale market

A proposal gaining traction is splitting of the wholesale market. The idea is to decouple low marginal cost renewable power from high marginal cost dispatchable power, e.g., by splitting the market based on technology type into separate markets for variable and firm power. This avoids the wholesale market price primarily being set by gas prices. It could also help stabilise prices in future when there is a greater proportion of renewable power, and prices would otherwise swing between high prices set by gas generation and low prices set by high renewable output.

Potential advantages:

• Encourage investment in renewable power by helping alleviate issues of price volatility and price cannibalisation^[16].
• Incentivise flexibility as more demands would look to buy from the lower cost, but less available, ‘variable’ market. Additionally, flexible technologies like batteries could benefit from access to both markets and shifting demand for price difference opportunities.
• Reduce need for long-term government support, e.g., through contracts for difference (discussed later).

Potential disadvantages:

• Uncertain implementation as this type of market has not been adopted by any major power market, and many variants have been suggested.
• Competition with other reform proposals as most of the benefits can likely be delivered through other ways.
• Lack of protection for end-users to the complexity and increased cost of not engaging with both markets.
• Lower liquidity (volumes which can be traded) in each individual market resulting in reduced competition between technologies.

Splitting the wholesale market could improve the long-term sustainability of investing in renewable power in Scotland. There would be a long-term market in which profits can be made, with more stable prices, and a reduced reliance on government support. However, it is possible that other reform proposals can provide the benefits outlined, and there could be a lack of additionality.

The wholesale market price is currently set by the last generator to turn on to meet demand. This is determined by the free market nature of the GB electricity market where bilateral trades can be made between any generator and demand, or through short-term power exchange markets. The flexibility of the current power system is primarily through flexing gas-fired power plants which means that these are the last generator to meet demand. Therefore, the wholesale electricity price is usually tied to gas prices.

As the proportion of electricity generation from wind and solar sources increases, there have been increasing concerns around the lack of effect of the high proportion of low-marginal cost renewable power on electricity prices. This non-effect on prices is a consequence of the liberalized electricity market. This has led to calls for reform on the wholesale market to better suit the net zero transition and to provide investment and operational signals to support the roll-out of mass renewable power. The current gas crisis with huge increases in the prices of gas has exacerbated this issue, increasing the voices supporting reform.

An alternative to the wholesale price formation is to move to pay-as-bid pricing where generators would receive what they bid, rather than the highest bid. This could decouple gas prices and electricity prices. However, it is likely that generators will bid higher than marginal cost to close the gap to the highest bid, resulting in a market price just below the price of electricity produced by gas power plants. Market intervention by limiting bids could mitigate this, but it is unclear how this could be implemented in practice.

Locational pricing

Locational pricing sets prices at a more granular spatial level than current national pricing. In nodal pricing there are prices at each location in the transmission network; and in zonal pricing the network is split into zones, each with a price, where it is assumed there are negligible network constraints. In both structures the prices incorporate the physical constraints of the network and includes both the cost of the energy and the cost of delivering it.

Potential benefits of locational pricing:

• Reduce whole system costs by incorporating network costs, such as the balancing mechanism, into wholesale costs.
• Nodal system would resolve network congestion inherently and remove the additional costs of the balancing mechanism. Zonal pricing would still likely require a balancing mechanism but could substantially lower costs.
• Strong signal for investing in technologies in the locations which can reduce whole system costs.
• More efficient network investment, as greater integration of network constraints in the electricity markets.

Potential disadvantages:

• Mismatch between where the greatest renewable energy sources are and where the congestion issues are for the network. For example, offshore wind offers greater capacity factors but is physically on the edge of the network.
• Potential for increased payments to existing CfD contracts as these generators are likely already existing in areas where the locational price will be lower than national price.
• Benefits of locational pricing can be greater for fossil fuel power plants (for issues such as ramp up rates and start-up costs), but with the net zero transition these benefits will be diminished.
• Greater consumer exposure based on location.
• Low liquidity in zones or nodes.
• Greater infrastructure requirements to manage the more complex system.
• For zonal pricing there is uncertainty in defining zonal areas and actual returns.

Scottish Renewables has spoken out against location pricing with a central argument being the difference in planning systems across the UK with different stakeholders holding varying interests [29]. They argue for reform of the TNUoS, the current network charge, which is locational based, as an alternative.

There would be a large impact on the Scottish power system with reform to locational pricing. Scotland has substantial wind resource with a large proportion of onshore wind farms and with large capacities of offshore wind in the pipeline. Locational pricing might have the impact of depressing prices received by these generators as locational pricing could be higher in England than in Scotland. This is because the main network congestion is currently delivering renewable generation from Scotland to England.

The motivation of locational pricing is to encourage generators and flexibility operators to take account of the real physical constraints in the network. This can result in investing and operating in areas which have higher value to the whole system and should provide higher rewards for generation and flexibility technologies. This can lead to more efficient location of new resources and efficient expansion of the network. Generators are provided with an incentive to locate to areas of high demand to access higher electricity prices. It also incentivises increased demand in areas which high renewable resources, but lower existing demands (and therefore prices). Since new and recent renewable generation often use contracts for difference this needs to be accounted for in any locational pricing design. Nodal pricing has recently been advocated by the National Grid [30] and the Energy Systems Catapult [31].

There is also interest in extending the granularity to local markets at the distribution level where there is responsibility for a distribution network operator to balance a local market. These local markets would interface with the existing national wholesale market.

Contracts for difference

Contracts for Difference (CfD) is the primary mechanism currently used by the UK government to support deployment of mass low-carbon power. A CfD contract guarantees a ‘strike price’ for generation. When market prices are below the strike price generator income is topped up and when market prices are above the strike price generators must pay back into the scheme. The scheme has seen the cost of renewables drop, by providing long-term certainty which reduces the cost of capital, as well as attracting investors. Strike prices are set through competitive auctions via pots for different technologies with set levels of government support.

Reform of CfDs is being considered since a greater proportion of total generation could end up being CfD supported in the transition to a net zero energy system. This raises issues around the lack of incentives to operate flexibly, locate in areas which help the network, and in competition with other generation technologies. Potential reforms are centred around increasing market exposure, such as a strike range, as opposed to a single price, to increase market exposure, and topping up payments based on comparison to wholesale prices over a week rather the current method of comparing prices in each half-hour pricing period.

Revenue cap and floor

Revenue cap and floor contracts would guarantee generators a minimum revenue over a contracted period. Their application to generators is inspired by contracts offered to 11,000 MW of interconnectors. An advantage is guarantees to investors of minimum revenue levels which helps minimise risk. Generators then have the freedom to participate in all the different electricity markets and attempt to maximise revenue. A cap is also implemented which if revenue exceeds, then the difference is paid back to the government.

Flexibility

Flexibility in the current electricity system comes from dispatchable fossil fuel power stations which can respond to demand changes and variable output from renewable power sources. In the net zero transition there will be a need to increase low carbon flexibility technologies. This includes renewable generation which can respond in different timeframes; and storage including batteries and long duration storage (see CCC report for more details [32]). Compressed air energy storage, Hydrogen, interconnectors offering firm low carbon power from countries like France (nuclear) and Norway (hydro), and demand-side flexibility such as electric vehicles and heat pumps could all have a role.

The UK government currently envisions that flexibility should be incentivised through pricing signals in the wholesale and balancing markets. There have been proposals to ensure these signals better reflect the need of the whole energy system, and therefore ensure flexibility is built in the right locations:

• Revenue cap and floor (similar as for low-carbon generation described earlier) so that flexibility technologies can participate in the full range of markets, but with the safety net of a minimum revenue which can strengthen investor confidence and interest.
• Supplier obligation where suppliers are required to achieve a set target for procuring flexibility.
• Reforming the capacity market to encourage technologies with different flexible characteristics (e.g., response time, duration of response, and location).

Capacity adequacy

It is of vital importance that market arrangements enable secure investment in the required capacity to ensure that electricity supply and demand are matched, and the ‘lights do not go out’. This is most difficult to achieve in extreme cases, such as during demand peaks (often a winter peak) and, very importantly in future, during long periods of low wind. These periods are currently primarily met through fossil fuel power plants such as gas CCGTs. However, many of these power plants are set to retire in the transition to net zero. Additionally, low marginal cost renewable power will displace high marginal cost fossil fuel power plants in the wholesale markets reducing revenues for these firm sources of electricity.

Proposed reforms for capacity adequacy are:

• Enhanced capacity market: Currently, the capacity market is the mechanism for topping up revenues for generators who can provide capacity adequacy. However, the majority of support has gone towards fossil fuel generators, highlighting the need for mechanisms which support low-carbon firm capacity. An enhanced capacity market would target low-carbon technologies which can provide flexibility and support capacity adequacy. Essentially, the capacity market would become more targeted and selective. This could be done through separate auctions or multiple clearing prices, with a careful balance of avoiding target setting which can supress competition.
• Strategic reserve: In this proposal a central authority auctions for reserve capacity on top of the capacity which is built through other markets. This would essentially act as a backstop to ensure security of supply without further intervention in existing markets.
• Operability: A number of proposals for reform around operability have been put forward. Capacity adequacy is an issue related to ensuring that extreme cases which the market does not account for does not result in system failure. Operability is how these assets then perform to ensure power grid stability. These involve evolving the existing suite of ancillary markets to increase the level of low-carbon technologies.

The issue of capacity adequacy is important for the Scottish electricity system, particularly as Torness nuclear power plant is due to close, and the gas CCGT at Peterhead needs to change to carbon capture and storage technology to be compatible with the net zero future. A potential enhanced capacity market should take account of the issues specific to Scotland and this has been highlighted as location is a characteristic which has been described as important to consider.

Contracts for difference

The CfD looks set to continue as the primary support mechanism for the roll out of mass low-carbon power [15]. This means that renewables in the Scottish energy system will continue to receive long-term contracts to provide stable income. It has also been suggested that older renewable generators, previously supported through ROCs or independently, could be offered a CfD contract.

Revenue cap and floor

Revenue cap and floor contracts could accelerate the roll out of wind power in the Scottish electricity system, while also incentivising flexibility such as batteries. This option could help improve the security of supply for Scotland, but it is not clear if this option would perform better than CfDs.

Flexibility

In Scotland there is likely to be an increased need for flexibility given the increasingly high penetrations of VRE generation. Therefore, it is important that changes to electricity markets incentivise situating flexibility technologies in Scotland. Current markets are not suited to delivering the flexibility required and while there are options being explored, it is not clear that the proposed reforms will deliver the required levels of flexibility in Scotland.

Future Energy Scenarios

The FES is widely recognized as a comprehensive and authoritative source of information and analysis on the future of GB electricity system. The data released as part of FES22 includes regionalised breakdowns of generation capacity, storage capacity, and demand for each grid supply point^[17] and transmission network area. National Grid use a combined bottom-up and top-down modelling approach^[18], and a series of stakeholder engagements to determine the regional data [33]. The four scenarios in FES are:

• Leading the Way is the fastest credible decarbonisation pathway of the four scenarios and includes significant lifestyle change and a mixture of Hydrogen and electrification for heating.
• Consumer Transformation has a lower speed of decarbonisation than leading the way but includes high societal change with consumers willing to significantly change behaviour. This scenario assumes electrified heating, high energy efficiency, and demand side flexibility.
• System Transformation has the same speed of decarbonisation as Consumer Transformation but with fewer changes in consumer behaviour and higher reliance on system-level development. This scenario assumes Hydrogen for heating, lower energy efficiency, and supply side flexibility.
• Falling Short is the slowest credible decarbonisation pathway and the only scenario which falls short of net zero by 2050. It assumes minimal behaviour change and decarbonisation in only power and transport, not in heat.

Heat demand and Hydrogen in FES

The System Transformation scenario assumes that most heating is met by Hydrogen, which results in a lower peak demand than in Consumer Transformation (heating is primarily electrified) and Leading the Way (mixed approach to heating). It should be noted that this perspective is not consistent with the Scottish Government’s Hydrogen Action Plan [34], which states that Hydrogen is intended to support a portion of domestic heating systems while also having potential for various alternative market opportunities.

Despite this difference, both plans share similar levels of ambition in promoting Hydrogen production capacity and usage. The Hydrogen Action Plan for Scotland projects a renewable Hydrogen production capacity of 5 GW by 2030 and 25 GW by 2045 within Scotland, which is comparable to the projections in the System Transformation plan (6 GW by 2030 and 69 GW by 2045 for the entire UK). Hydrogen produced by electrolysers are assumed in FES to not operate during the peak demand period. This assumes large-scale infrastructure including Hydrogen storage is connected to a distribution network which can deliver Hydrogen to end users.

PyPSA-GB details

PyPSA-GB^[19] has been developed to simulate the GB power system in high spatial and temporal resolution for both historical and future years [16]. The data included in the model has been sourced from openly available datasets found online. Code for PyPSA-GB is written in Python and Jupyter Notebooks are used to showcase data, functionality, and analysis.

For the historical years, 2010-2020 inclusive, PyPSA-GB includes data on generators, marginal prices, demand, renewable power, and storage. Simulating historical years can provide insight into the operation of the GB power system, e.g., dispatch of thermal power plants and curtailed renewable generation. It is also useful in order to compare to historical data and build confidence in the model.

For future years, PyPSA-GB includes data to simulate future years based on National Grid’s FES2021 and FES2022 for all four scenarios which go up to 2050. Steady Progression represents business as usual with low level of both societal change and speed of decarbonisation and is the only scenario which fails to meet the net zero target. Leading the Way represents the highest speed of decarbonisation coupled with a high level of societal change. Consumer Transformation and System Transformation represent the same speed of decarbonisation, but Consumer Transformation requires higher level of societal change than System Transformation.

The power dispatch functionality utilises the open-source PyPSA (Python for Power Systems Analysis) to perform network-constrained linear optimal power flow calculations. PyPSA can calculate linear optimal power flow by least-cost optimisation of power plant and storage dispatch within network constraints, using the linear network equations, over several snapshots. In this study, models and data in PyPSA have been used: meshed multiply-connected AC and DC networks, with controllable converters between AC and DC networks; standard types for lines; conventional dispatchable generators; generators with time-varying power availability, such as wind and solar generators; storage units with efficiency losses; simple hydroelectricity with inflow and spillage. In this work simulations were carried out in hourly timesteps over a year.

Security of supply metric calculations

Listed below are the formulae for calculating loss-of-load expectation (LOLE), loss-of-load probability (LOLP) and de-rated system margin:

where the LOLP for a particular period is defined as the probability that available generation is unable to meet demand:

where X_t is the available generation and D_t is the system demand, both of which are random variables. A typical example for T and t is a time horizon of one year with periods of one hour.

The de-rated capacity margin measures the amount of excess supply above peak demand. De-rating means that the supply is adjusted to take account of the availability of plant, specific to each type of generation technology. The technology-specific de-rate factors are given in Table 5 and Table 6 [22] in Appendix 12.13.

De-rated system margin is used as a proxy for risk of loss of supply. It is calculated as the difference between the peak demand and the de-rated supply capacity. The de-rated supply capacity is calculated by scaling down installed capacity by the expected availability at peak demand, and by converting variable generation capacity using an equivalent firm capacity (EFC) factor. The EFC is a measure of the capacity adequacy contribution provided by wind and solar. It refers to the amount of power that a wind or solar farm can consistently deliver over time, which is useful to translate the variable output into an equivalent amount of firm capacity in the calculation of security of supply. EFC can be much lower than capacity factor, as the capacity factor reflects the average output of a wind farm, while the EFC reflects the reliability and consistency of that output. For example, the latest winter outlook, 16.1% is used as the EFC factor for wind generation.

GB supply under System Transformation

Figure 26 Plot of de-rated supply capacity, peak demand and supply margin of GB for System Transformation from 2025 – 2045

Figure 26 shows de-rated capacity and system margin results for the entire GB system, which includes the Scottish electricity system. The overall system margins of GB also vary in the future, peaking at 18% by 2035 after a rapid increase in generation capacity from 2025, and then falling back to 11% by 2045 when the rising demand catches up. It is evident from these results that the GB system margin is substantially less than that of the Scottish system alone. While the generation capacity in Scotland may seem excessive in the context of security of supply for only Scotland, it will be utilised to decarbonise and provide security of supply to the rest of GB.

Figure 27 shows power dispatch for all of GB for the System Transformation scenario and includes time of peak GB demand. The majority of generation is from variable renewable energy sources (VRES) – solar photovoltaics, wind offshore, and wind onshore – while nuclear slowly increases to the peak demand period. Firm generation – a combination of Hydrogen, CCS gas, hydro, and biomass and storage (pumped storage hydroelectric, batteries, compressed air, and liquid air) – are dispatched around the peak demand and at times of low VRES generation. It is notable that the period of highest use of firm generation and storage is at a period of low VRES and high demand which happens after the peak GB demand.

Figure 27 Power dispatch of whole of GB for System Transformation in 2045 over 2-day period, excluding interconnectors to Europe.

Security of supply stress tests

Base case

The base case shows the power dispatch for the System Transformation scenario over a 6-day period from 5 December to 10 December, and can be used as a comparison to the stress test power flow figures.

Figure 28: Power dispatch modelled over the 6-day period for base case.

Offshore wind farm failures

In security planning, the ability of an electrical power system to handle failure of its largest generator is tested. Historically this has been a large, centralised fossil fuel power plant. However, in 2045, the largest single generator in Scotland will be from the network of offshore wind farms.

Figure 29 Power dispatch modelled over the 6-day period the stress event of the failure of offshore wind farms.

Figure 29 is the power dispatch modelled over the 6-day stress event of the failure of offshore wind farms^[20]. The power dispatch shows use of hydrogen power plants which were not dispatched in the base case. It is notable that CCS gas is not dispatched. The reason hydrogen is dispatched first is due to modelling assumptions with the marginal cost of hydrogen being lower than CCS gas. Despite the dispatch of hydrogen there is still export to the rest of GB. The effect of the failure of offshore wind farms is increased use of hydrogen generation, storage discharging, and imports from the rest of GB.

Low VRES power output

Scotland will be increasingly reliant on VRE in the form of wind power. This stress test analyses how the electricity system copes with a prolonged period of low VRES power output.

Figure 30 Power dispatch modelled over the 6-day period the stress event of low-VRES power output. Not lower scale on GW y-axis than other power flow figures

Figure 30 is the power dispatch modelled over the 6-day period the stress event of low-VRES power output during the peak demand period. There are substantially more periods of import to make up for the reduction in renewable power generation in Scotland, while hydrogen and biomass power plants are at full output, aided by dispatch of all storage types (pumped storage, battery, compressed air, and liquid air). As with the offshore wind farm failure, there are still exports to the rest of GB, however this does result in periods when Scotland is a net importer of electricity.

Gas power generation in Scotland unavailable

Figure 31 Power dispatch modelled over the 6-day period for the stress event of unavailable gas power generation.

Figure 31 shows power dispatch modelled over the 6-day period for the stress event of gas power generation not being available in Scotland. This has a much smaller impact on power dispatch compared to the wind power issues of the previous two stress tests, even with the dispatchability of the CCS gas. This is because the CCS gas is 1,800 MW in 2045 compared to the 21,000 MW wind farm failure in the first stress test.

Interconnectors to NI and Norway unavailable

Figure 32 Power dispatch modelled over the 6-day period the stress event of interconnector to Norway and Northern Ireland being unavailable.

Figure 32 shows the power dispatch for the stress event where both the interconnectors to Norway and Northern Ireland are unavailable. This results in some wind generation being reduced, or curtailed, as there is less capacity to export.

Connection to rest of GB unavailable

There will be more reliance on the connection between Scotland and the rest of GB in the future to accommodate increases in power flow. Increased imports to Scotland will be required to meet demand when there is low wind generation, and exports to the rest of GB will increase due to large installed capacities of wind generation in Scotland and to decarbonise demands in the rest of GB.

Figure 33 Power dispatch modelled over the 6-day period the stress event of no connection between Scotland the rest of GB

Figure 33 shows the power dispatch modelled over the 6-day period for the event of no connection at all between Scotland and the rest of GB. This results in power dispatch which is almost entirely reliant on wind generation coupled with charging and discharging of pumped storage plus other storage types. Wind generation over this period is enough to meet the demand of Scotland, however, there is no ability to export to the rest of GB which means that lots of potential wind generation is curtailed.

Storage failures

Flexibility in the electricity system will increasingly come from storage, as opposed to the dispatchability of traditional fossil fuel power plants. While large, centralised fossil fuel power plants offer a single source of failure, storage technology such as batteries, pumped hydro, compressed air energy storage, and liquid air energy storage will likely be distributed through the electrical network in a larger number of individual units. Therefore, storage will likely offer a higher degree of reliability, but this may be offset by uncertainty around the state of charge, i.e., how much electricity can be discharged from the storage unit.

Figure 34 Power dispatch modelled over the 6-day period the stress event of no battery storage in Scotland.

Figure 34 shows the power dispatch modelled for the stress event of no battery storage in Scotland. This has minimal impact compared to the base case but does decrease the utilisation of wind generation resulting in less import and export. The pumped hydro appears suited to making up for the loss of battery storage.

Security of supply data requirements

Probabilistic data is required to calculate the LOLE, LOLP, and de-rated system margin. An important input is the probability that each generator will be available at any time. This is characterised by the rate at which a unit is likely to experience forced outages, and will vary between generators depending on the technology, age and operating regime. With the outage rate (or given as availability factor = 1 – outage rate), the probability distribution for available supply capacity can be constructed using the Capacity Outage Probability Table method developed by Billinton and Allan [35].

The approach taken in this report is to use generation data from the FES22 scenario for technology capacities, and to use expected availability factors assumed in the latest 2022 National Grid’s Winter Outlook [22] and National Grid’s ESO Electricity Capacity Report [21]. This data of outage rate per type is summarised in Table 5. The de-rating factor applied for duration-limited storage (i.e. battery), is directly linked to the duration, as shown in Table 6. For instance, a storage system with a power rating of 100MW and a duration of 3 hours (equivalent to an energy capacity of 300MWh) would have a de-rating factor of 66.18%. The aggregate cumulative distribution function (cdf) for available generation, using 2030 in the System Transformation scenario as an example, are displayed in Figure 35.

Table 5 Generation de-rate factors and outage rate used in this study

Table 6 De-rate factors for duration limited storage

Figure 35: Cumulative distribution function (CDF) for available generation in 2030 ST scenario. For illustrative purposes, an indictive peak demand of 10 GW is shown as a vertical line, and probability for not meeting the level of demand is 0.25. For peak demand around 5.5 GW, which is what is forecasted in Scotland, the probability for not meeting the level of demand would be statistically zero based on the CDF curve.

Data for Scotland under Leading the Way

Data for Scotland under System Transformation

Data for Scotland under Consumer Transformation

Data for Scotland under Falling Short