Reducing emissions from Scotland’s tourism sector is a crucial part of reaching the Scottish Government’s target of net zero greenhouse gas (GHG) emissions by 2045.

Emissions from tourism cut across passenger transport, accommodation, food and drink, culture, retail and outdoor recreation, so reliable data is required. Current data, however, only reports over broad categories such as ‘transport’ or ‘buildings’ and does not isolate the contribution from visitor activity.

In this report, researchers explore how they can measure GHG emissions from Scotland’s tourism sector in a way that is credible, repeatable, and trackable over time. The primary aims of this research were:

• To identify a practical methodology for a reliable, national-level estimate of tourism-related GHG emissions.
• To examine the potential for separating results by factors such as geography, visitor or accommodation type to support place-based policy
• To ensure the chosen approach aligns with established GHG measurement practices and can be maintained through routine updates while balancing coverage, granularity, cost, and capacity.

Findings

• Scotland’s tourism sector has distinctive characteristics, including geography, rural tourism, transport emissions, seasonal workforce, and post-COVID behavioural changes.
• There is broad consensus on definitions of “tourism” across the literature, with studies organising indicators according to the United Nations World Tourism Organisation’s (UNWTO) Measuring the Sustainability of Tourism (MST) framework.
• Tourism Satellite Accounts (TSAs) – data sets providing economic analysis of a country’s tourism industry – are critical for defining the economic boundary of tourism, separating visitor-driven activity from resident activity, and enabling reporting.
• Four major methodology types for assessing GHG emissions in tourism are identified:
  • Environmentally‑Extended Input-Output (EEIO) analysis is suitable for establishing a robust, repeatable national baseline.
  • Life Cycle Assessments (LCA) provide detailed insights for operational decision-making.
  • Hybrid models can combine the strengths of both approaches.
  • Survey-based methods are useful for capturing regional behaviour and supplementing other models.

Recommendations

The report’s headline recommendation is to take a proportionate, staged pathway that matches effort to ambition. It suggests: 

• Conducting a comprehensive audit of Scotland’s available data, including Input-Output tables, environmental accounts, and surveys such as the International Passenger Survey (IPS) and the Great Britain Tourism Survey (GBTS).
• Establishing an EEIO baseline as the analytical backbone, updated regularly using repeated survey data.
• Developing a Scotland-specific Tourism Satellite Account to enable greater precision, sector splits, and geographical disaggregation.
• Running LCA pilots for selected assets or services to provide operational insight and validate baseline assumptions.

Over time, these elements could be integrated into a hybrid framework under formal governance and quality assurance, reporting both production- and consumption-based perspectives. A staged, proportionate approach provides a clear, low-risk path to a credible baseline and repeatable evidence base, supporting policy and industry efforts to track and reduce tourism-related emissions.

Further recommendations

The report also outlines steps that should be taken in development of the methodlogy, regardless of the final methodology chosen:

• Adopt the IRTS definition of tourism and structure the GHG account within the UNWTO MST framework.
• Main active links with those that are further advanced, such as Denmark, to learn best practice.
• Build the methodology around a mix of data sources and keep data management central to project governance.
• The approach should be designed for regular repetition, and to secure the resources needed for scheduled updates.

For further information, please read the report.

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

Community benefits are additional benefits offered by renewable energy developers to support communities. Examples include community benefit funds and in-kind benefits provided by developers such as investment in local infrastructure improvements or funding for education programmes. Community benefits currently operate on a voluntary basis in Scotland.

The Scottish Government has published Good Practice Principles for onshore and offshore energy in Scotland, which are currently under review. Within the context of that overarching review, the primary aims of this research were: 

• To help identify any necessary adjustments to Scotland’s current voluntary community benefits approach for onshore and offshore to better support communities and industry as part of a just transition.
• To understand how different renewable energy technologies affect the provision of community benefits. 
• To understand how mandating community benefits could work in practice for onshore renewable energy technologies.

The research incorporated an evidence review, qualitative interviews and the design and testing of a socio-economic analysis framework.

Findings

• No obvious adjustments need to be made to Scotland’s current community benefit approach.
• Financial aspects of a renewable energy project (costs, revenue and financial viability) are key factors impacting community benefit levels. Projects with higher amounts of revenue, and more robust and predictable financial returns are better positioned to offer significant community benefits.
• It is easier to offer community benefits for projects involving more established technologies like onshore wind, compared to newer technologies like hydrogen.
• The literature reviewed did not allow for a satisfactory comparative analysis of the in-practice impacts of mandatory versus voluntary approaches.
• Further development and more complete data is required to make a functional framework that could inform policy decisions on the appropriate levels of community benefit for different renewable energy technologies.

For further information, please read the report.

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

Research completed: July 2025

DOI: http://dx.doi.org/10.7488/era/6396

Executive summary

Research background and aims

Community benefits are additional benefits offered by renewable energy developers to support communities. Examples include community benefit funds and in-kind benefits provided by developers such as investment in local infrastructure improvements or funding for education programmes. Community benefits currently operate on a voluntary basis in Scotland. The Scottish Government has published Good Practice Principles for onshore and offshore energy in Scotland, which are currently under review.

Within the context of that overarching review, the primary aims of this research were:

• To understand how different renewable energy technologies affect the provision of community benefits. This included developing and testing a socio-economic analysis framework to understand the factors that influence the nature and level of community benefits associated with different renewable energy technologies.
• To understand how mandating community benefits could work in practice for onshore renewable energy technologies.
• To help identify any necessary adjustments to Scotland’s current voluntary community benefits approach for onshore and offshore to better support communities and industry as part of a just transition.

The study methodology incorporated an evidence review, qualitative interviews, and the design and testing of a socio-economic analysis framework. This research focused on the factors influencing how different renewable energy technologies affect developers’ provision of community benefits, rather than on the experiences and perspectives of recipient communities. Interviews were therefore conducted with renewable energy developers.

The Scottish Government is gathering other non-industry perspectives on community benefits, including the views of community members, through a public consultation on the Good Practice Principles.

Understanding the ability of different technologies to offer community benefits

One of the ways this research explored how renewable energy technologies affected developers’ ability to offer community benefits was to develop and test a socio-economic analysis framework. This framework set out the parameters assumed to influence the level and nature of community benefits. An initial set of seven draft parameters were developed by the Scottish Government and the research team. Following an assessment of the feasibility of measurement and feedback from renewable energy developers, four parameters were recommended for further consideration (and which are subsequently referred to as “the framework”). These were:

• Technology maturity (i.e. more mature technologies, with well-established supply chains and business models, may better allow developers to build community benefit provision into their project plans compared to newer technologies).
• Market maturity (i.e. maturity may influence investor confidence, competition between developers, and certainty in supply chains which may in turn determine predictability of financial plans and therefore ability to deliver community benefits).
• Deployment and operating costs (i.e. the costs associated with developing and operating different renewable energy technologies may impact the financial capacity to provide community benefits).
• Revenue and profit (i.e. a project’s revenue and profit will impact on its overall financial viability which may impact on its ability to delivery community benefits).

This study identified significant challenges in developing a single framework to assess how different technologies affect developers’ provision of community benefit. For such a framework to work as a practical, decision-making tool, quantitative data on the economics of different renewable energy technology projects would be required. However, existing public data is sparse and of inadequate quality and many developers were unable or unwilling to share commercially sensitive data about their projects. A further limitation was that existing data (e.g. on the value of community benefits from individual renewable energy projects) is based on actual provision rather than an assessment of potential. Additionally, data available is largely historical and therefore challenging to use when anticipating new technologies and emerging economic and regulatory models.

However, it was clear from interviews with developers that the financial aspects of a renewable energy project (costs, revenue and financial viability) were key factors impacting community benefit levels. They noted that projects with higher amounts of revenue, and more robust and predictable financial returns are better positioned to offer significant community benefits. Conversely, if the financial viability of a development is low, then it is unlikely it can offer monetary community benefits without the project becoming non-viable. Developers noted that both technology maturity and market maturity can have an impact on a project’s financial viability and are therefore, indirectly, also linked to a project’s ability to deliver community benefits. However, this was based on qualitative interviews and was not possible to measure using quantitative data.

Developers also reported that it is easier to offer community benefits for projects involving more established technologies like onshore wind, compared to newer technologies, due to the latter’s comparatively lower profit margins. Less mature technologies (e.g., floating offshore wind, hydrogen) can have higher risks, higher delivery costs, less predictability in cost and performance, and lower investor confidence which can impact on their ability to offer benefits.

Although not necessarily directly impacting the level of benefit offered, developers identified community engagement as key factor for effective delivery. Developers emphasised the importance of levels of community engagement and capacity to effectively manage and deliver benefit funds. Interviewees highlighted the importance of community engagement, consultation and feedback in moulding community benefit initiatives, ensuring more meaningful and tailored contributions. This is difficult to quantify and would therefore be challenging to include in a socio-economic analysis framework.

How mandating community benefits could work in practice (for onshore renewable technologies)

The available literature does not enable a comparison of the real-world impacts of mandatory, as opposed to voluntary, provision of community benefits. Mandatory community benefits as part of renewable energy infrastructure development exist in Denmark and Ireland, specifically for wind projects. However, the literature reviewed does not allow for a satisfactory comparative analysis of the in-practice impacts of mandatory versus voluntary approaches.

Existing onshore developers felt that the following factors should be considered:

• clear guidance on what the financial expectation attached to mandating is to avoid any potential for confusion;
• allowing for the differences between individual onshore technologies to be taken into account;
• retaining a degree of flexibility, particularly in terms of allowing for community benefits to be designed around the needs of communities;
• avoiding overly burdensome processes. For example, in relation to restrictions on how communities should spend the money.

The power to mandate community benefits is reserved to the UK Government. In May 2025, the UK Government published a working paper seeking views on a mandatory community benefits scheme for low carbon energy and mechanisms for shared ownership of onshore renewables^[1]. This includes the option to utilise existing powers to mandate offering shared ownership.

Any necessary adjustments to Scotland’s current voluntary community benefits approach for onshore and offshore

This research has not identified any obvious adjustments that need to be made to Scotland’s current community benefit approach.

The literature highlights that the Scottish Government is leading the way across the UK in highlighting the role of communities in the development of renewable projects. While there are examples in the literature of other approaches to community benefit provision outside of Scotland (e.g. in Ireland and Denmark), there is limited evidence directly comparing how different approaches have impacted the level of community benefits delivered. Therefore, there are no clear lessons from these international approaches suggesting a need to change the current approach in Scotland.

Guidance from the Scottish Government, in the form of Good Practice Principles and a recommended community benefit contribution of £5,000 per installed MW per year for onshore projects, was highlighted in interviews with developers as being a strength of the current process. They felt it provided a degree of predictability while also allowing for flexibility in application. However, for projects of emerging and/or non-generative technologies, developers noted that more targeted guidelines would be beneficial, noting that there is no established industry standard approach.

Conclusion and recommendations

The intention was that the framework examined in this study could inform policy decisions on the appropriate levels of community benefit for different renewable energy technologies. However, further development and more complete data is needed to be functional for this purpose. Collating the required data would need considerable resources and rely on information that developers perceive to be commercially sensitive. Considering data gaps, collection challenges, the difficulty in sourcing data specifically focused on future ability to offer benefits (rather than actual performance), further research and/or alternative approaches would be required. For these reasons, the approach explored here does not provide a robust enough evidence base to underpin a framework for use as a decision-making tool.

The report highlights existing measurement tools and guidance that can be used to understand where a project sits in relation to certain parameters, such as technology and market maturity. Further data collection work would be needed to make the most of these tools for robust socio-economic analysis. This would involve collecting relevant data for a large number of projects across metrics with established measurement tools. This would require a significant time and resource commitment and may not be a practical option.

To better understand how different renewable energy technologies affect developers’ provision of community benefits further research, beyond the financial indicators highlighted, would be needed. Considering the challenge of sourcing quantitative data on project economics, further qualitative research may be the most feasible option. Ideally this would be with a larger selection of developers across the full technology spectrum (including those that had not been able to deliver community benefits), direct engagement with communities, and wider stakeholder engagement (e.g. project investors, funders and other partners that have assisted in project development). This type of engagement would add to and build on the insights from developers gathered in this study.

Introduction

This report presents findings from research exploring opportunities for providing community benefits from renewable energy projects using different technologies in way that is fair and consistent. The research was carried out by Ipsos on behalf of ClimateXChange and the Scottish Government.

Background to the project

The Scottish Government has set ambitious targets for achieving net zero emissions by 2045, emphasising the importance of renewable energy technologies in this transition. The Climate Change Plan update (2020)^[2] sets out Scotland’s ambition of a transformed energy system, which supports sustainable economic growth across all regions of Scotland.

Communities are at the heart of the energy transition in Scotland. Community benefits are additional benefits offered by renewable energy developers to support communities, offering them an opportunity to work with renewable energy businesses to secure long-term benefits. They provide an opportunity to share in the benefits of the energy resource and can have lasting social and economic impacts^[3].

The Scottish Government published Good Practice Principles for the onshore^[4] and offshore^[5] energy sectors to outline how they can achieve a positive legacy for local communities. The approach and nature of community benefits operates on a voluntary basis in Scotland, with the guidelines allowing for flexibility in benefits arrangements offered by industry. Decisions on mandating community benefits are reserved to the UK Government. In May 2025, the UK Government published a Working Paper on community benefits and shared ownership for low carbon energy infrastructure, seeking views on whether mandating is the right approach and if so, to inform the design of future policy proposals.

Good Practice Principles have been widely adopted, but the approach to community benefits has not been wholly consistent across developments. In recognition of this, and of the rapidly changing sectoral and policy landscape, the Scottish Government is undertaking a review of the Good Practice Principles to ensure that guidance continues to help communities and developers get the best from community benefits.

This research sits within that overarching review. It was designed to help the Scottish Government understand more about different approaches to providing community benefits and to explore the opportunities for providing community benefits in future in a way that is fair and consistent for industry and communities. The findings from this research will help to inform a refresh of the Good Practice Principles.

Aims and objectives

The primary aims of this research were:

• To understand how different renewable energy technologies affect developers’ provision of community benefits. This included developing and testing a socio-economic analysis framework to understand the factors that influence the nature and level of community benefits associated with different renewable energy technologies.
• To understand how mandating community benefits could work in practice for onshore renewable energy technologies.
• To help identify any necessary adjustments to the Scottish Government’s current voluntary community benefits approach for onshore and offshore to better support communities and industry as part of a just transition.

The findings aimed to support policy development and further refinement of guidelines and frameworks to help ensure that community benefits are effectively and fairly integrated into Scotland’s net zero energy system and strategy.

Methodology

The research involved a mix of desk research, qualitative interviews with developers and data analysis, as outlined below (detailed methodology is in Appendix A):

• A desk-based evidence review that explored examples of community benefits from onshore and offshore renewable energy technologies in the UK and other countries. Literature sources reviewed included 12 peer reviewed academic papers, 20 reports, 2 guidance documents from grey literature (e.g., renewable energy developers, private consultancies) and 1 policy document. These were all published between 2011 and 2024, with 22 documents from the last 5 years.
• Initial scoping interviews with four industry representative bodies to understand their views on current community benefit approaches and to explore options for sourcing data that could support socio-economic analysis on community benefits.
• Design of a socio-economic analysis framework to help understand the factors which are likely to affect the level and nature of community benefits.
• In-depth interviews with 21 industry developers from a range of renewable energy technologies (see Appendix A). As the focus was on how different renewable energy technologies affect provision of community benefits, qualitative research with developers was carried out to help understand the views of those with direct experience of working with projects and benefits. Interviews helped to understand industry perceptions towards community benefits arrangements, collect feedback on the proposed analytical framework, and to understand availability of relevant data for socio-economic analysis.
• Assessment of the suitability of a framework to act as a tool for the Scottish Government to understand what type and level of community benefit may be suitable for different renewable energy technologies, based on data availability and feedback from interviews.

Definitions

Community benefits are defined in this research in line with the Scottish Government’s Good Practice Principles:

Community benefits are additional benefits, that are currently voluntary, which developers provide to the community. The Scottish Government does not currently have the power to legislate for community benefits, which lies with the UK Government. A community benefit fund is considered to be a fundamental component of a community benefit package, though other measures may be considered such as in-kind works, direct funding of projects, or any other voluntary site-specific benefits. Community benefits are not compensation for impacts on communities or other interests, including commercial interests, arising from renewable installations and they are not taken into account in a decision over whether a consent for a development is granted.

Community benefit in Scotland is distinct from shared ownership. Shared ownership provides community groups or members of a community the opportunity to make an investment in a commercially owned renewable energy project. This includes any structure which involves a community group as a financial partner benefitting over the lifetime of a renewable energy project. As shared ownership is not considered a form of community benefit in Scotland, it has not been included within this research.

In this report renewable energy technologies have been interpreted as the range of technologies outlined in the Scottish Government’s draft Energy Strategy and Just Transition Plan^[6]. This includes onshore wind, offshore wind (both floating and fixed), solar, hydro, pumped hydro storage, battery energy storage system (BESS), hydrogen, and carbon capture, utilisation and storage (CCUS).

Limitations

This study was limited by data availability. Existing public data (for example on community benefit values, project costs and revenue) is sparse and of inadequate quality to effectively measure the parameters within a socio-economic analysis framework. Many developers were unable or unwilling to share commercially sensitive data about their projects. A further limitation was that existing data (e.g. on the value of community benefits from individual renewable energy projects) is based on actual provision rather than an assessment of project’s potential capability. Additionally, existing data are largely historical and therefore challenging to use when anticipating new technologies and emerging economic and regulatory models. Consequently, data gaps mean it was not possible to develop a fully functioning socio-economic analysis framework as part of this study.

A further limitation is that this research draws on the views of a relatively small sample of developers. These represent one group of perspectives on community benefits, albeit from different organisations, working with different technologies. Non-industry perspectives, including those of community members themselves, were not included in the remit of this study and would not be expected to fill the data gaps highlighted above.

Current community benefit arrangements

This chapter details the current arrangements for delivering community benefits, based on findings from the literature and from the qualitative interviews with renewable energy technology developers. At various points, examples of community benefit projects identified in the literature are shown to help illustrate the findings.

Key findings

• The literature highlights that the Scottish Government is leading the way across the UK in highlighting the role of communities in the development of renewable projects and in providing good practice guidelines.
• Community benefits from renewable energy projects in the UK mainly involve community benefit funds^[7], but there are also examples of in-kind benefits such as investment in education and infrastructure programmes. Community benefit funds are not as extensively adopted outside of the UK.
• Onshore wind has more established community benefit practices than other onshore and offshore technologies. However, a key similarity is that all projects, regardless of technology, tended to adopt both community benefits funds and in-kind contributions.
• There is limited evidence directly comparing how different approaches in the UK and in other countries have impacted the level of community benefits delivered.

Guidelines for community benefits

According to the reviewed literature, the Scottish Government is leading the way across the UK in highlighting the role of communities in the development of renewable projects. The Good Practice Principles for Community Benefits from Onshore Renewable Energy Developments (updated in 2019) and the draft Good Practice Principles for Community Benefits from Offshore Renewable Energy Developments (2018) outline how the energy sector can achieve a positive, lasting legacy for local communities, and a range of successful community benefit projects have been implemented to date.^[8] These guidelines have been widely adopted across the renewables industry, providing best practice for the sector.^[9]

The voluntary guidelines suggest practices like conducting impact studies to identify affected communities, engaging in consultations, and tailoring benefits to local context and needs. These principles aim to ensure benefits are well-targeted and meet community expectations, which could be seen as markers of a well-designed scheme.^[10]

Example 1.

Beatrice Offshore Windfarm’s Community Benefits Fund used the Scottish Government’s Good Practice Principles to guide the development of the fund. The Beatrice Community Benefits Fund also undertook innovative analysis of the potential wider impacts of the community benefits funding, using a Social Return on Investment methodology.^[11] This illustrates the ability of the Good Practice Principles to be applied alongside other models and approaches.

In Scotland, the Scottish Government also established the Community Benefits Register,^[12] managed by Local Energy Scotland. It can be viewed online and offers a form of third-party reporting and public recognition.^[13] Best practice guidance also exists in England, Ireland, the Netherlands and Germany (see Table 2 in Appendix B).

Approaches used in the UK and elsewhere

The literature provided examples of different approaches to designing and implementing community benefits schemes. However, most examples are from onshore wind farms, with some examples given from offshore wind technologies. There is very little to no reference to other renewable technologies such as hydrogen, hydro, solar, wave, thermal, or BESS.

Community benefit mechanisms referred to in the literature included^[14]:

• Financial contributions to a community benefit fund, to be used as directed by the community to invest in local initiatives^[15];
• In-kind contributions to local infrastructure, facilities, or services^[16];
• Grants, scholarships, or donations to support community initiatives^[17];
• Electricity discounts or subsidies for local residents^[18];
• Provision of environmental or recreational amenities.^[19]

While these approaches share many similarities, there are some notable differences and ambiguities. These include varying interpretations of what constitutes the “local community” (especially for offshore projects)^[20] and differing emphasis on the rationale for providing benefits (e.g., impact mitigation).

This section describes the different approaches to community benefits in more detail. Differences between the UK and other countries are noted, where available.

Community benefit funds

Community benefits from renewable energy projects in the UK are primarily delivered through community benefit funds. The UK onshore wind industry, in particular, has well established approaches for this.^[21] Through this mechanism, developers voluntarily contribute a certain amount of funding to local communities. In some cases, the level of funding is linked to the amount of installed capacity of the project or the amount of energy produced. For example, in Scotland, it is the industry norm for onshore wind projects to typically deliver £5,000 per megawatt (MW) of installed capacity per year in alignment with the Good Practice Principles for Onshore Renewable Energy Developments.^[22] However, the per MW model is not the only approach used and the total amount provided is based on the agreement between the developers and the community.

Example 2.

Crossdykes Wind Farm near Lockerbie, Scotland (developed by Muirhall Energy) offered an industry-leading £7,000 per MW per year for a community benefit fund, well above the industry standard of £5,000 per MW per year. The project provided an Initial Investment Fund of £100,000 to support community projects during the wind farm’s construction phase, showing a proactive effort to deliver early benefits.

Example 3.

Brechfa Forest West Wind Farm in Wales (owned by RWE Renewables), is an example of a community-administered community benefit fund which is expected to provide £11 million in community benefit funding, administered by the local enterprise agency and a volunteer panel of residents.^[23]

Regarding offshore wind, the concept of community benefits in the UK is relatively newer and more flexible than for onshore, reflecting the evolving nature of the industry.^[24] Some, predominantly near-shore English and Welsh wind farms (e.g. North Hoyle and Rhyll Flats off the North Wales coast) have followed the pattern of the onshore wind farms, with benefits pro rata to MW size, although at a much lower rate.^[25] However, in many cases, and for some of the large North Sea distant offshore wind farms, the benefits packages have been more ad hoc and much smaller (pro rata) than for onshore projects.^[26] Several challenges have been identified with providing community benefits funds for offshore wind projects, including defining the relevant community to be targeted.^[27]

Example 4.

The Hornsea/Race Bank East Coast Community Fund, off the Norfolk coast, is managed independently by a specialist grant-making charity, GrantScape, on behalf of the developer Orsted. This enables an arms-length, transparent allocation process.^[28]

According to a number of the literature sources, allocation and spending of community benefit funds are usually determined by developers, in collaboration with the local communities, often through local trusts or organisations. Developers often strive to tailor the benefits based on local priorities identified through community engagement.^[29] Community benefit funds can take different forms, ranging from local funds – investments in communities nearest to developments to enhance services, assets and activities of residents – to regional funds – investment in transformational projects to provide socio-economic growth for wider communities.^[30]

The evidence reviewed suggests that community benefit funds are not as extensively adopted outside of the UK. There are some instances of community benefit funds in Europe. Notably, in Denmark, from 2008-2018, the state-run “Green Scheme” mandated payments per kilowatt per hour of production to host communities. As of 2020, Danish developers must pay fixed amounts per MW installed into green funds for affected municipalities under the “Green Pool” scheme and make annual payments to neighbouring residents under the “VE-Bonus” scheme, with amounts determined by the Danish Energy Agency.^[31] In Ireland, renewable energy auctions require developers to contribute €2 per MW hour to a community benefit fund, with defined spending allocations.^[32]

Among the developers interviewed for this research, flexible community benefit funds were the most common approach being taken to community benefits in Scotland. The exact sum delivered through these funds varies project-by-project. Onshore wind developers said that they follow, and often exceed, the Good Practice Principles guidelines of £5,000 per MW per year. For other technologies, which developers said often have greater financial uncertainty and/or smaller margins than onshore wind, the levels of community benefit are less predictable. Developers said that the level of benefit is often closely linked to the project’s costs and financial returns, which varies.

“We typically work backwards from what we think the returns in the scheme are going to look like. And that’s very site specific, dependent on abnormal costs, grid costs, land rights costs…Depending on what that looks like, we’ll then generate a number to determine what we can reasonably offer local communities.” – BESS developer

In a number of cases, these funds are administered by Foundation Scotland, a charitable organisation that helps to support communities to set up, manage and distribute their funding. This has particularly been the case where local communities may lack the capacity to manage significant financial resources independently. Some projects also have established their own governance arrangements, involving boards constituted of local community members to determine the allocation of these funds.

Other community benefit mechanisms

Other examples of community benefits mechanisms that appeared in the literature include tax revenues or fiscal contributions from wind farm developers, which go directly into funding local infrastructure and community services. From the documents reviewed, this is common practice in Germany, Poland, Croatia, France and Italy. ^[33]

Example 5.

The Block Island offshore wind farm development in Rhode Island, USA, is an example of fiscal contributions being made to support local infrastructure. In this case, a formal Community Benefit Agreement was developed in which the wind farm company pays for improvements to town infrastructure where the cable comes ashore. This project was also highlighted in the literature as an example of community engagement resulting in locally appropriate community benefits and high levels of support for the development from the local community. As part of the public consultation on the project proposals, the developer, Deepwater Wind, collaborated with the town council to invite stakeholders and hired consultants from the local community to represent local interests. This helped establish trust and perceptions of fairness in the process.^[34]

The literature also identified Australian examples of neighbourhood benefit programmes.^[35] These programmes aim to address concerns around fairness that can arise when local residents receive no direct benefits from a renewable energy project which affects their experience of their place and community.^[36] Examples of the types of benefits provided via these neighbourhood benefit programmes include support towards home energy efficiency measures, the installation of residential solar PV, and contributions to electricity bills for neighbours or neighbourhood community facilities (e.g. local hall, local fire-fighting facilities).

The reviewed literature suggests that the involvement of local authorities in the delivery of community benefits varies by country. In some European countries (including Denmark, Germany, France, Italy and Spain), the local municipality plays a significant role and often decides funding priorities of community benefits. In the UK and Ireland, local authorities generally decline involvement to avoid conflicts of interest in the planning process. However, Highland Council recently set out plans for a different approach to community benefit decision making and fund distribution and Shetland Council approved a new set of principles around community benefit.

Developers interviewed also described the types of in-kind benefits they offer communities. Examples included:

• Employment and education programmes. This includes providing funding towards training in green technologies, especially in areas that are reliant on traditional energy industries rather than renewable energy.
• Electricity discount schemes, with money coming off local residents’ bills.
• Investment in environmental and net zero initiatives, including activities designed to reduce carbon footprint and support biodiversity in communities, along with awareness-raising around these issues.
• Infrastructure improvements such as broadband access, roads and pathways, and community recreational facilities.

Impact of different approaches on the level of community benefits delivered

Based on the literature reviewed, there is limited evidence directly comparing how the different approaches in the UK and in other countries have impacted the level of community benefits delivered.

Among the documents reviewed, the only source that explicitly offers comparative analysis between approaches in the UK and European countries was the Department of Trade and Industry report conducted by the Centre for Sustainable Energy, which involved detailed case studies of major wind farms in the UK, Germany, Denmark, Ireland and Spain. The following points are drawn exclusively from this report:

• The overall levels of benefits accruing to communities from wind projects in Denmark, Spain and Germany tend to be higher than in the UK. However, it is important to note that in such countries, community benefits are mostly associated with shared ownership practices, and therefore economic and financial benefits are linked to those practices. Shared ownership is not included in the Scottish Government definition of community benefits and it is also worth noting that developments outside of the UK will have different policy contexts and market conditions to those in the UK, making it difficult to directly compare.
• While the authors do not find robust evidence that higher benefits directly lead to higher levels of support for developments, they suggest that they are likely an important factor in sustaining long-term acceptance of projects.

Lessons from community benefits projects

Common themes emerged from the literature and interviews around what constitutes good practice in community benefit:

• Early community engagement. Establishing trust, building relationships with local residents and identifying concerns and priorities early on can lead to smoother running of the project and help dispel fears of community members early on. ^[37]
• Ensuring community representation in the co-design and administration of community benefits^[38] as this can help establish trust and lead to higher levels of sustained support for the project.^[39]
• Providing broad and flexible community benefit. Literature and interviews highlighted the value of funds being used to support a wide range of community priorities like infrastructure, schools, housing, elderly care, environment, etc. that improve quality of life for residents. ^[40]
• Community capacity was noted by developers as a factor that can impact on their ability to deliver community benefits. Not all communities were seen to have the resources or expertise needed to administer funds efficiently. They noted that the existence of strong community councils or Community Development Officers to help generate ideas have helped contribute to successful community benefit funds.
• Ensuring transparency of communication and providing full information to communities through trusted messengers is seen in the literature as a crucial step in securing support from communities.^[41]
• The reviewed literature also suggests that formalising benefit commitments and monitoring progress can promote accountability and sustainability over the long-term. It helps ensure developers deliver on promises made to communities.^[42]
• There is also evidence that partnering and aligning with local government, NGOs and other companies allows projects to leverage additional resources and maximise the scale and impact of their community investments.^[43]

Understanding how different renewable energy technologies affect the ability to offer community benefits

One of the ways this research explored how renewable energy technologies affect the level of community benefits offered by developers was to develop and test a socio-economic analysis framework. This framework set out the parameters assumed to influence the level and nature of community benefits provided. This chapter outlines the steps taken to develop and test a framework and the extent to which this tool could help to understand how different renewable energy technologies affect the level community benefits provided by developers.

Key findings

• Within the scope of this study, the available evidence did not support a single framework to robustly determine how different technologies affect the provision of community benefits. For such a framework to work as a practical, decision-making tool, quantitative data on the economics of different renewable energy technology projects would be required. However, existing public data is insufficient to effectively measure the parameters in the framework, and it was not possible within this study to gather the level of quantitative data that would be needed for robust socio-economic analysis.
• However, it was clear from the interviews with developers that the financial aspects of a renewable energy project (costs, revenue and financial viability) were key factors impacting community benefit levels.
• Developers’ feedback also highlighted that it is easier to offer community benefits for projects involving more established technologies like onshore wind, compared to other technologies (e.g. offshore wind, solar and battery storage) due to the latter’s comparatively low profit margins.

Original framework parameters

The initial parameters identified at the scoping phase of the project are outlined in Table 1. The following section sets out the feedback received from developers in response to this framework, and the extent to which these parameters are measurable within a framework.

Table 1 Initial list of identified parameters affecting provision of community benefits

Community benefit value

There is a lack of data on the level of community benefits offered by renewable energy projects. The Local Energy Scotland Community Benefits Register is currently the most comprehensive data source for capturing the community benefits monetary measures. However, this is not exhaustive and does not cover the full range of renewable energy technologies.

Further steps were therefore taken to identify additional and more up-to-date data for this research. Firstly, data was requested from developers taking part in interviews, but not all were willing or able to share this (either because they could not access the data, or due to commercial sensitivities). Secondly, online searching for publicly available information on monetary values of community benefits was carried out. While data for some projects is available publicly, this requires a significant time commitment to source since it is not held in a central source nor in a consistent format. Therefore, data gaps remained after taking these steps. For the framework to be robust, a more complete set of data on community benefit value is required.

Technology maturity

Technological maturity is a widely used metric for gauging a technology’s development and readiness for deployment.

Developers generally felt that this could have an impact on the viability of a project, and as a result affect the level of community benefits. Some agreed that, compared to mature technologies (e.g., onshore wind), technologies such as floating offshore wind, BESS and hydrogen can have higher risks, higher delivery costs, less predictability in cost and performance and lower investor confidence. However, some onshore wind developers argued that more mature technologies do not always have more secure financial models because recent cost increases in their supply chains have made viability harder to predict.

Technology maturity is suitable for quantitative measurement using the NASA Technology Readiness Level (TRL) scale (see Appendix E for details). To accurately assess a technology’s TRL, it is recommended that individual projects are approached directly for scoring, as they may employ different versions of the technology. If direct assessment is not possible, it would be possible to utilise the International Energy Agency’s ETP Clean Energy Technology Guide, which evaluates and provides comprehensive information on each technology’s current development stage across the energy system.

This parameter could be included in a socio-economic analysis framework, provided there was sufficient data available or one of the existing guides outlined above could be used.

Market maturity

Factors influencing market maturity include established supply chains, business models and supporting physical and regulatory infrastructure (ports for deployment of offshore wind, standards for solar farms, etc.).

Developers felt that emerging technologies and immature markets face difficulties determining an appropriate level of community benefits because of uncertainty around securing investment and finances. However, some onshore wind developers also noted that their more mature market can still experience challenges with supply chains, especially in relation to costs of deployment (e.g. turbine costs have increased).

Market maturity could be measured using existing tools. The Adoption Readiness Level (ARL) framework, developed by the U.S. Department of Energy, is a tool for assessing the commercialisation risks of new technologies. It helps identify potential roadblocks to market adoption, such as cost-competitiveness, regulatory landscape, public perception and infrastructure availability. It also helps evaluate market demand by identifying the target market, understanding customer needs, and assessing the competitive landscape.

The ideal approach to understanding this parameter would involve project-level assessments via direct engagement with project owners, using the scoring framework available online^[44]. However, given the large number of projects, this endeavour would be challenging. The decision to pursue this should weigh the uncertainties about the parameter’s significance in determining community benefits, with the time commitment needed to collect this information.

This parameter would be suitable to include in a socio-economic analysis framework, but the ability to source the level of data required is challenging.

Project size or energy yield

This measure is quantifiable, based on the level of energy capacity installed for each project expressed in MW. This data is available on the Local Energy Scotland’s Community Benefit Register and the Renewable Energy Planning Database (REPD). To enable a comparison between different technologies, it is important to convert installed capacity to expected energy yield as each technology has different levels of efficiency.

Capacity and energy yield are both inputs in the estimation of gross revenue. Therefore, inclusion of these metrics as stand-alone parameters in the framework would be duplicative and would correlate very highly with any revenue estimations. For this reason, these metrics would not need to act as stand-alone parameters in an analysis framework but could be used as inputs to the revenue estimation.

Deployment and operating costs

The total costs of developing and operating a renewable energy project captures an important financial aspect assumed to influence the level of community benefit commitment.

Developers noted that the developmental and operating costs impact the financial capacity for a project to provide community benefit. As with revenue, obtaining precise cost figures would involve direct input from project owners. Again, due to commercial sensitivities and challenges in accessing this data, estimating total cost of production might need to rely on publicly available sources. This can be done for a selection of technologies using the Department for Energy Security and Net Zero’s Levelised Cost of Electricity (LCOE) estimates.^[45] It is worth noting that not all REPD project technologies are included in this resource, and hence, some projects will require mapping to the closest matching technology category. Despite this challenge, a basic methodology for estimating LCOE from generation technologies is outlined in Appendix D.

When looking at non-generation projects, i.e. storage projects, it is important to reflect the differences to generation projects in the calculation of costs. An analogous version of the LCOE is the Levelised Cost of Storage (LCOS), which uses charging cost as fuel cost and uses the discharged electricity instead of generated electricity. Given the lack of access to the necessary data it is not possible to accurately estimate LCOS for storage projects.

Given that project costs provide a direct link to the financial aspects that are assumed to influence community benefits, it is recommended to include this parameter in a socio-economic analysis framework.

Revenue and profit

Developers agreed that the amount of revenue generated by a project has an impact on their ability to deliver community benefits and the level of community benefits that can be offered.

Ideally, obtaining precise revenue figures would involve direct input from project owners. However, due to commercial sensitivities and challenges in accessing data, estimating revenue might need to rely on publicly available sources. It is important to note that this approach is based on significant assumptions that might not hold true over time. Estimating future revenues is particularly challenging because it depends on projected electricity prices, which are notoriously difficult to predict with accuracy or extend into the future. Despite these challenges, a basic methodology for estimating revenues from generation technologies is outlined in Appendix D.

When it comes to non-generation projects, revenue estimation becomes even more complex and uncertain. These types of projects may involve diverse sources of income and variables, requiring a more nuanced approach to estimation. Battery storage projects generate revenue through a variety of mechanisms, often stacked together to maximise returns. Key revenue streams include arbitrage (buying electricity when prices are low and selling it back to the grid when prices are high), grid services (e.g. frequency regulation, voltage support), capacity market participation and ancillary services (e.g. black start capability). The lack of publicly available data for each of these revenue streams make it challenging to estimate revenue for non-generation projects.

Given that revenue estimation provides a direct link to the financial aspects that are assumed to influence community benefits, it is recommended that consideration is given to including this parameter in a socio-economic analysis framework.

Land use, visual and environmental impacts

There are several challenges associated with quantitatively measuring land use, visual, environmental and social impacts:

• Quantifying land use involves assessing the physical footprint of a project, which can vary significantly based on the type and scale of the renewable technology employed. Further challenges arise in comparing land use impacts across different technologies, such as wind farms versus solar arrays, as each may occupy land differently (e.g., spacing between wind turbines versus solar panel coverage). These differences between technologies were also noted by developers.
• Visual impact assessments are inherently subjective and can vary depending on individual perspectives and local landscape characteristics. Moreover, accurately quantifying visual impacts requires sophisticated modelling tools and surveys that consider factors like visibility range, landscape context, and viewer sensitivity.
• Comprehensive environmental impacts involve a multitude of factors, including potential effects on local wildlife, ecosystems, water resources, and biodiversity. Data collection for environmental impacts may be inconsistent and require long-term monitoring to capture seasonal or cumulative effects accurately.
• Social impacts can include effects on local communities, employment opportunities, and cultural shifts, which are difficult to measure quantitatively and may require qualitative research approaches. In addition, assessing social impacts often involves engaging with communities and stakeholders, which can introduce variability and complexity in data collection and interpretation.
• Each of these aspects often interacts with others, making it challenging to isolate and assess impacts individually without considering cumulative or synergistic effects. Variability in methodologies and data availability can also lead to inconsistent measurements and comparisons.

For these reasons, this parameter is not suitable for a socio-economic analysis framework.

Wider economic impact of the project and its distribution

Renewable energy projects, especially large-scale ones, often generate significant economic benefits. For example, they may create high-value jobs through operation and maintenance, enhance the local supply chain and attract inward investments. These contributions can lead to substantial regional development and improved economic resilience.

However, there are notable challenges in confining these benefits strictly to the local communities most directly impacted by the projects. Economic effects often extend beyond the immediate vicinity. Moreover, quantifying these impacts presents difficulties, often necessitating self-reported data from projects. Such data can be subject to bias and may not fully capture the comprehensive economic changes occurring in the region. These challenges were reflected in interviews with developers. They noted that projects can add a lot of value to an area through high-value jobs, contribution to the supply chain and driving inward investment. However, they noted that it would be difficult to define this parameter, since the economic impacts may not be contained to the specific community in question. Projects can also incur wider costs, such as seabed option fees and rental fees for offshore wind renewable energy developments and these funds can have a wider economic impact.

Additionally, this metric’s applicability varies with different project types. For instance, projects involving CCUS often repurpose existing infrastructure, without necessitating a new workforce. As a result, the direct local economic impacts of such projects might be limited, underscoring the need for careful consideration when using this metric to assess community benefit commitments.

Wider economic impact provides a valuable lens for understanding potential benefits. However, the challenges and variability associated with measuring and applying this parameter across project types should be carefully evaluated to ensure fair, accurate and consistent community benefit determinations. For these reasons, this parameter is not suitable for a socio-economic analysis framework.

Community involvement and capacity

During interviews, developers suggested that community involvement and capacity influence the ability to provide community benefits and should be considered as part of a framework. This parameter focuses on the role of communities in both shaping and managing the benefits derived from renewable energy projects. Interviewees highlighted that placing community needs at the core is essential for ensuring that the type and level of benefits align with local priorities. They emphasised the importance of community engagement, consultation, and feedback in moulding these initiatives, arguing that this involvement leads to more meaningful and tailored contributions.

Additionally, while not directly impacting a developer’s ability to offer community benefit, the capacity of communities to effectively manage and deliver agreed benefits was seen as important. Interviewees pointed out that variations in the size and organisation of community councils or other community groups can significantly impact their ability to administer benefits. Hence, recognising these differences allows developers to support and enhance the local capacity, fostering increased participation and benefit realisation from the projects.

However, there are several challenges to quantitatively measuring these aspects. Quantifying community engagement and feedback is subjective, as perceptions of effective engagement vary among stakeholders. Communities often have diverse and evolving needs, making standardisation difficult. Additionally, while the number of consultations can be counted, assessing their quality requires qualitative data, which is harder to quantify. Asking the community to accurately capture and record this data would put significant burden on individuals who quite often are volunteers in the community. Moreover, community needs can change over time, necessitating ongoing updates and flexible metrics.

Due to these challenges, it is not recommended to include this parameter as a stand-alone element in a socio-economic analysis framework.

Conclusion

Following the assessment outlined above, four parameters were deemed suitable to be considered in a socio-economic analysis framework. These were:

• Technology maturity
• Market maturity
• Deployment and operating costs
• Revenue and profit.

To demonstrate how a framework could be used in future, socio-economic analysis has been carried out based on a sample of data on renewable energy projects (see Appendix C). The parameters in scope of this analysis are restricted to those which have been deemed feasible to measure and for which a suitable method to measure them has been identified. This analysis is based on data available from the Community Benefits Register Database, supplemented with additional data sourced through desk research. Due to the data sources available, it only includes onshore wind, offshore wind and hydro technologies.

Key findings from that analysis are:

• Industry alignment and policy influence: While many onshore wind and hydro projects in Scotland are clustering around the recommended annual £5,000 per MW capacity for community benefits for onshore technologies, more than half of the onshore wind and hydro projects analysed in the available data set commit less than the recommended amount.
• Revenue-benefit correlation: A positive correlation exists between gross project revenue and total community benefit commitments, with larger projects providing bigger packages. However, this relationship weakens for high-revenue projects, suggesting a potential plateau effect.
• Costs and benefit packages: There is a positive correlation between total cost of production and total community benefit packages across all project sizes, suggesting that as total costs increase, so does the size of the overall commitment to community benefits. While this may appear contrary to the views of developers shown earlier (i.e. those who said that high costs can impact on financial viability and therefore their ability to offer community benefits) it should be noted that this data analysis is based only on projects already providing monetary benefits. It excludes those that had not yet provided any community benefits. It can therefore be assumed that the dataset excludes those projects that were deemed not financially viable enough to enable community benefit provision.

In interpreting these findings and considering next steps it is important to acknowledge the distinction between the willingness of projects (measured by actual provision) to provide community benefits and their ability to provide community benefits. The analysis above is based on actual provision of community benefits. It could be assumed that these commitments are indicative of both willingness and some inferred level of ability, but the data does not allow for an assessment of the capability of projects (and different technologies) to offer these benefits. The UK Government’s Contracts for Difference (CfD) scheme is the main support mechanism for renewable energy projects. It is important to acknowledge that although community benefit funds are not recognised costs in the CfD framework, they are often treated as part of a project’s overall cost base and priced in to CfD bids.

Robust analysis of the capability to provide community benefits would require detailed project-level data. To collate the data needed will require considerable resources and will also require renewable energy technology developers to share data they perceive as commercially sensitive, which may be unrealistic. This work has highlighted considerable data gaps, challenges collecting data in the future and difficulty in sourcing data specifically focused on future ability to offer community benefits rather than actual performance. Therefore, the approach explored here does not provide a robust enough evidence base to underpin a framework for use as a decision-making tool.

To better understand the capacity for projects to provide community benefits, it is suggested that further research and / or alternative approaches may be needed. This could take the form of qualitative research with a larger selection of projects across the full technology spectrum, to understand perceived barriers or enablers of moving from willingness to ability. This should offer insights into the practical challenges faced by projects. Longitudinal case studies may prove beneficial to understand how changes in policy, economic conditions or market incentives could have influenced both the willingness and perceived capacity to make these commitments.

Exploring mandatory community benefit arrangements

This chapter looks at current approaches to mandating found in the evidence review and the views of the industry on how mandating community benefits for onshore technologies could work in practice, based on qualitative research with developers.

Key findings

• Mandatory community benefits approaches exist in Denmark and Ireland, as part of renewable energy infrastructure development for wind projects. However, the literature reviewed does not allow for a satisfactory comparative analysis of the in-practice impacts of mandatory versus voluntary approaches.
• Existing onshore developers felt that the following factors would need to be considered for mandating to work in practice:
• clear guidance on the financial expectation attached to mandating
• accounting for differences between individual onshore technologies
• retaining a degree of flexibility, particularly in terms of the ability for community benefits to be designed around the needs of communities
• avoiding overly burdensome processes.

Current approaches to mandating community benefits

Mandatory community benefits as part of net zero energy infrastructure development exist in Denmark and Ireland, specifically for onshore and offshore wind projects. Other countries have mandated approaches for shared ownership, special taxes, energy subsidies, or monetary compensations, but not community benefits as defined here. This includes Germany, France, Taiwan, and the Philippines ^[46].

Denmark has a history of various mandates relating to community benefits. For example, until 2018, the “Green Scheme” required the Danish state to pay hosting communities a fixed amount per kWh of production from new turbines. This applied to offshore wind farms built outside the tender process and within 8km of shore.^[47] More recently, as of June 2020, regulations require offshore wind developers to pay fixed amounts per MW installed into green funds for affected municipalities. The payment is DKK 115,000 per MW (around €15,500).^[48] Additionally, in Ireland, renewable energy auctions mandate that developers contribute €2/MWh to a community benefit fund, with defined criteria for how the funds must be spent.^[49]

Other mandated approaches similar to community benefits include special taxes imposed on developers, that are distributed to local authorities, and electricity subsidies for “host communities”. The former approach has been implemented in France and Germany. The French Maritime Wind Turbine Tax is imposed on offshore wind farms, and is allocated to local authorities to finance local projects, per a defined formula. Germany requires that tax revenue generated from offshore wind farms in the Exclusive Economic Zone is distributed to coastal states. Energy subsidies for host communities have been implemented in the Philippines and Taiwan. Since 2008, the Philippines has required that 80% of money generated from royalties, or government shares in renewable projects, must be used to subsidise the electricity costs of communities affected by these projects.^[50] In Taiwan, the Electricity Assistance Fund (EAF) is distributed to communities affected by power plant projects (including, but not limited to renewable energy) according to a pre-defined formula. For example, in the case of offshore wind, 30% of EAF funds are provided to “local project fund pools” for the benefit of residents, community groups, and civil society organisations, and 70% is provided for councils and fishery associations.^[51]

Although shared ownership is seen distinct from community benefits in Scotland, some other countries have mandated shared ownership or compensation payments. For example, in Denmark, the 2008 Renewable Energy Act mandated developers to offer at least 20% of shares in wind projects for sale to local households within 4.5km of a turbine.^[52] Similarly, in Germany, several states have required that between 10% and 25% of wind farm shares be offered to local residents and municipalities. Mandated compensation payments to nearby residents and community funds have been implemented in Denmark and Ireland. Since 2020, Irish legislation obliges wind farm developments to provide an annual contribution to nearby households and communities.

While some of the literature reviewed implies that mandated approaches are more robust,^[53] no clear evidence is provided of their outcomes and impact compared to voluntary approaches. The literature does not allow for a satisfactory comparative analysis of the in-practice impacts of mandatory versus voluntary approaches.

Developers’ perspectives on how mandating community benefits could work in practice

Industry stakeholders shared their views on the potential for mandating community benefits for onshore technologies. Mandating was explored in both the scoping interviews with representative bodies and in the main interviews with developers. Developers highlighted some key considerations that they felt should be borne in mind for how mandating could work in practice.

For mandatory community benefits to work in practice, developers felt that there would need to be clear guidelines on what the financial expectation is to avoid any potential for confusion. It was suggested that the community benefit value attached to any mandated approach should be realistic and determined in collaboration with industry to help clarify what the expectations are for developers and for communities.

To work in practice, it was felt that mandatory community benefits would need to take into account the differences between different technologies. For example, by having different levels of benefits that technologies are expected to contribute. Specifically, some interviewees highlighted the different operating contexts and economies (e.g. different capital costs) between some technologies. Further, it was suggested that hydrogen and CCUS should be treated differently because they are designed to complement renewable technologies by operating only when needed. Therefore, it was argued that it is difficult to tie community benefits to specific metrics for these.

“[If] it would be used to set an X amount per megawatt, [then] that would need to be split into different technologies because it’s not a clear cut case for all technologies. It has to show this is what it is for BESS, what is for wind, what is for solar. Because if you get that number wrong, you can make the scheme unviable or unattractive and therefore it will not come forward.” – BESS stakeholder

It was also felt that for mandating to be practical, the approach to community benefits should retain some degree of flexibility and the ability to be designed around the needs of individual communities. For example, one onshore and offshore wind developer said if mandating were to happen it should be around the amount of funding that should be provided and not how communities spend the money. This view echoes findings of a report by BiGGAR Economics (2023) that states that the current voluntary system has allowed communities and developers to be flexible in their arrangements, and has enabled the “formation of mature, collaborative relationships” between parties. ^[54]

Related to the point above, some developers felt that, in practice, mandates could mean a more bureaucratic process which could slow things down, in turn impacting developers’ ability to deliver benefits. Stakeholders made contrasts with the current system, which was perceived as “fairly simple” and “flexible”. Therefore, it was suggested that approaches to mandates should avoid overly burdensome processes and bureaucracy. For example, it was suggested that it should avoid having too many restrictions around timescales or conditions on how communities should spend the funding.

Another view from developers was mandating might impact on the existing relationships between developers and communities, as it could move away from a collaborative process to one where there is a firmer expectation around what developers are required to give. Therefore, the approach would need to consider the relationships between developers and communities. Developers particularly felt it important to avoid community benefits appearing like compensation. For example, it was felt that creating a mandated system through which a certain amount is paid made directly to homeowners could lead to the system feeling like a form of compensation.

“If it’s mandated, it absolutely can’t be attributed as compensation to the community. If money had to be paid to compensate people for the effects of a wind farm, then the wind farm shouldn’t be being built.” – Multi-technology stakeholder

Aside from practicalities, a key concern raised was that mandating community benefit provision could risk investor confidence. Some developers felt that mandatory community benefits would have an impact on financial viability of projects, which could make investors less confident to invest. It was suggested that they may choose to invest in projects in other countries that do not have a community benefit mandate or in which they feel the approach is more straightforward.

“The danger with [mandating] is that it creates investor concerns. There’s a lot of competing geographies around the world that want money for renewable energy projects…If one country becomes difficult or the risks are harder to understand, they’ll move that investment to another country where they understand it. And the UK, and especially Scotland, runs a real risk of upsetting investor confidence, which is already very delicate because of the situations with the grid at the moment.” – Solar PV stakeholder

As the scope of this research was focused on understanding how different renewable technologies influence the level of community benefits offered by developers, interviews were conducted with a sample of renewable energy developers. A wide range of other stakeholders will have views.

Adjustments needed to Scotland’s current voluntary community benefits approach

This chapter sets out the extent to which any adjustments are required to the current voluntary community benefits approach based on findings from the literature review, interviews with developers and the design and testing of a socio-economic analysis framework.

Key findings

• This research has not identified any obvious adjustments that need to be made to Scotland’s current community benefit approach. Developers felt that the current system could better acknowledge the different realities of different technologies, but they were not specific about what the best future approach should be.
• Developers felt that guidance from the Scottish Government, in the form of Good Practice Principles and a recommended level of community benefit for onshore projects was a strength of the current process. However, for projects of emerging and/or non-generative technologies, developers noted that more targeted guidelines would be beneficial, noting that there is no established industry standard approach.
• The intention was that the framework in this study could be used by Scottish Government to determine an appropriate expectation of the level and types of community benefit required for different renewable energy technologies. This work identified significant data gaps, challenges collecting data in the future, and the difficulty in sourcing data specifically focused on future ability to offer community benefits rather than actual performance. For these reasons, the framework explored here is not robust enough to use as a decision-making tool.

Lessons from literature and developers’ views

Based on the literature reviewed, there is limited evidence directly comparing how the different community benefit approaches in the UK and in other countries have impacted the level of community benefits delivered. Similarly, there is limited evidence to compare the impacts of mandated and voluntary approaches. International examples do not therefore provide any obvious lessons for the current approach in Scotland.

Onshore wind developers interviewed as part of this study were largely satisfied with the current arrangements. They felt that having a recommended standard (of £5,000 per MW per year for onshore) works well, helping them to predict what the cost associated with each project will be. Since it is a recommended, rather than compulsory standard, they also felt that it also allows for a degree of flexibility, meaning that the community benefit contribution can be responsive to both project and local community needs.

“That financial outlay [£5,000 per MW per year] is much more predictable in our models that we bake in during development…we actually really try to make sure that we can deliver it and protect it.” – Multi-technology developer

Developers of some less well-established technologies (e.g. hydrogen and pumped hydro storage) expressed a desire for clearer guidance from government on the appropriate levels of community benefit for these technologies. They suggested that new guidelines around levels of community benefit should take into consideration the differences in scale and impact between projects like pumped storage and hydrogen generation, which can be more expensive and less visible than wind projects. Those from non-generative technologies (e.g. BESS) felt that it is more difficult to determine the amount of community benefits (funds) that can be delivered from these projects because they have lower level of return (they do not yield energy) and serve a different function in the energy market than generation projects.

Developers also suggested that further structure and support for communities could help them to manage funds more effectively. They felt that community-led decision-making was vital for ensuring the funds meet local needs, but that this should be balanced with adequate administrative support to prevent the misuse or underutilisation of funds.

“There is also a misconception that communities are underspending this funding. Our analysis shows that if we invest and empower communities, then they are very capable of delivering impactful projects.” – Multi-technology developer

Lessons from testing a framework approach

As noted earlier, to effectively measure parameters identified in the proposed framework, project-level data would be required on costs, revenue, technology readiness levels and market maturity. Data on these metrics is not currently available and collecting this data would be a significant task.

Developers felt that certain parameters (see chapter 4) were considered suitable for a socio-economic analysis framework. However, their limited testing means that the framework would need more comprehensive data to fully model these parameters’ effects on community benefits. This is especially true for community benefit commitment data (£/MW/yr) which currently is only reported in the Community Benefits Register Database for onshore wind and hydro projects.

When discussing the idea of such a framework, developers noted that community benefits should not have a one-size-fits-all approach and should be reflective of specific circumstances of each technology and each project. Concerns were raised by some interviewees that a framework might lead to overly prescriptive approaches which could risk stifling development and deterring investment.

“Each [parameter] is relevant and I can see why they have been captured as things that would influence the value and viability of community benefits […] It all depends on an individual project basis, depends on what else is happening in terms of landscape and development.” – Multi-technology developer

Interviewees also questioned whether sufficient data would be available to support the framework and there was some concern about using historic data to understand future community benefit levels. A few interviewees also highlighted concerns about data sensitivity and need for any information to be carefully handled.

Considering the data gaps, challenges collecting data in the future, and the difficulty in sourcing data specifically focused on future ability to offer community benefits rather than actual performance, a single framework may not be the most appropriate approach.

Conclusions

This research looked at current and future approaches to community benefits to help inform decisions around future provision of community benefits in a way that is fair and consistent. This chapter draws conclusions around the three broad research aims:

• To understand how different renewable energy technologies affect the capacity of developers to provide community benefits, including developing and testing a socio-economic analysis framework.
• To understand how mandating community benefits could work in practice for onshore renewable energy technologies.
• To help identify any necessary adjustments to the Scottish Government’s current voluntary community benefits approach for onshore and offshore to better support communities and industry as part of a just transition.

Understanding how different renewable energy technologies affect community benefits

Within the scope of this study, the available evidence did not support a single framework to robustly determine how different technologies affect community benefits. For such a framework to work as a practical, decision-making tool, quantitative data on the economics of different renewable energy technology projects would be required. However, existing public data is sparse and of inadequate quality to effectively measure the parameters within a framework and many developers were unable or unwilling to share commercially sensitive data about their projects. A further limitation was that existing data (e.g. on the value of community benefits from individual renewable energy projects) is based on actual provision rather than an assessment of project’s potential ability. Additionally, data available is largely historical and challenging to use when anticipating new technologies and emerging economic and regulatory models.

However, from data that was available, it was clear that the financial aspects of a renewable energy project (costs, revenue and financial viability) were key factors impacting the developers’ offer of community benefits. Projects with higher amounts of revenue and more robust and predictable financial returns are better positioned to offer significant community benefits. Conversely, if the financial viability of a development is low, then it is unlikely developers can offer community benefits without the project becoming non-viable. Developers noted that both technology maturity and market maturity can have an impact on a project’s financial viability and are therefore, indirectly, also linked to a project’s suitability to deliver community benefits. As discussed above, while there are existing tools for measuring technology and market maturity, data gathering is challenging.

Developers’ feedback also highlighted that it is easier to offer community benefits for more established technologies like onshore wind, compared to other technologies (e.g. solar and battery storage) due to the latter’s comparatively low profit margins. Less mature technologies (e.g., floating offshore wind, hydrogen) can have higher risks, higher delivery costs, less predictability in cost and performance, and lower investor confidence which can impact on their ability to offer benefits.

While not directly impacting on the level of community benefits offered, developers noted the importance of community engagement and capacity to effectively manage and deliver benefit funds. Interviewees highlighted the importance of community engagement, consultation and feedback in moulding community benefit initiatives, ensuring more meaningful and tailored contributions. However, this is difficult to quantify and would therefore be challenging to include in a socio-economic analysis framework.

How mandating community benefits could work in practice (for onshore renewable technologies)

The literature reviewed does not allow for a satisfactory comparative analysis of the in-practice impacts of mandatory versus voluntary approaches. Mandatory community benefits approaches exist in Denmark and Ireland, as part of net zero energy infrastructure development for wind projects. While the literature provides examples of where this was happening outside of the UK, it was less clear on the extent to which mandating had an impact on the level and nature of community benefits when compared with voluntary approaches.

Developers felt that for mandating to work in practice, a number of factors would need to be taken into consideration. It was felt that any future mandating approach should allow for the differences between technologies to be accounted for by setting, for example, different recommended levels of community benefit fund value. For mandating to work in practice, it was also felt that flexibility was key, particularly in terms of how communities could make use of the funding provided. Practicalities aside, there was some concern that mandating could potentially pose a risk to projects, by placing a financial burden on some projects (particularly those with smaller financial returns such as solar and BESS technologies) which could pose a risk to investors.  

Any necessary adjustments to Scotland’s current voluntary community benefits framework for onshore and offshore

This research has not identified any obvious adjustments that need to be made to Scotland’s current community benefit approach.

Guidance from the Scottish Government, in the form of best practice principles and a recommended level of community benefit for onshore projects was highlighted in interviews with developers as being a strength of the current process. However, developers’ feedback suggests the current system needs to better acknowledge the different realities of different technologies. Developers of emerging and non-generative technologies suggested that more targeted guidelines for these newer technologies would be beneficial, noting that there is no established industry standard approach. However, while they suggested some areas for consideration, they were not specific about what the best future approach should be.

The intention was that the framework in this study could be used by the Scottish Government to determine an appropriate expectation of the level and types of community benefit required for different renewable energy technologies. The parameters that were considered suitable for the framework could provide a useful understanding of the factors that influence ability to offer community benefits. However, this would be dependent on data gaps being addressed. Ideally, it would have up-to-date data on community benefit value covering the full range of renewable energy technologies, with at least 50 projects for each technology.

This study has identified data gaps, challenges collecting data in the future and the difficulty in sourcing data specifically focused on future ability to offer community benefits rather than actual performance. The approach explored here does not provide a robust enough evidence base to underpin a framework for use as a decision-making tool.

Recommendations and next steps

The report highlights existing measurement tools and guidance that can be used to understand where a project sits in relation to certain parameters, such as technology and market maturity. To make the most of these tools, further data collection work would be needed before they could be used for robust socio-economic analysis. This would involve collecting relevant data for a representative sample of projects across the metrics that have already established measurement tools. This would require a significant time and resource commitment and may not, therefore, be a practical option.

To better understand the factors influencing the level of community benefit, beyond the financial indicators highlighted in this study, further research would be needed. Considering the challenge of sourcing quantitative data on project economics, further qualitative research may be the most feasible option. Ideally this would be with a larger selection of developers across the full technology spectrum (including those that had not been able to deliver community benefits), direct engagement with communities, and wider stakeholder engagement (e.g. project investors, funders and other partners that have assisted in project development). This type of engagement would add to and build on the insights gathered from developers in this study.

Glossary / abbreviations table

References

Anchustegui, I. H. (2021). Distributive justice, community benefits and renewable energy: The case of offshore wind projects.

Arsenova, M., & Wlokas, H. L. (2019). Local Benefit Sharing in Large-Scale Wind and Solar Projects. IFC.

Arsenova, M., Skyt, P., & Qadeer, A. (2024). The Strategic Value of Community Benefits in Offshore Wind Development. IFC.

BiGGAR Economics. (2023). Baseline report on Community benefit and shared revenue from onshore wind projects to communities in the south of Scotland.

BiGGAR Economics. (2024). Developing a new model to maximise local economic benefits from development in Moray and Highland. Report to Moray Council and Highland Council.

BiGGAR Economics. (2024). Impact Assessment of the Rosehall and Achany Wind Farm Community Benefit Funds.

Centre for Sustainable Energy (CSE), & Garrad Hassan. (2005). Community Benefits from Wind Power: A Study of UK Practice and Comparison with Leading European Countries.

Chen, H., Esram, N. W., Johnson, A., Harmon, D., Phelan, P., & Fraser, A. (2024). Aligning Community Benefits with Decarbonization Goals: Lessons Learned from Development of Community Benefit Plans for IRA Funds. American Council for an Energy-Efficient Economy.

Cowell, R., Bristow G., Munday, M. (2011) Acceptance, acceptability and environmental justice: the role of community benefits in wind energy development, Journal of Environmental Planning and Management.

Department for Energy Security and Net Zero (2023) Electricity Generation Costs (2023)

Additional LCOE estimates for generation technologies & Key data and assumptions for generation technologies. Available online: https://assets.publishing.service.gov.uk/media/6555cb6d046ed4000d8b99bb/annex-a-additional-estimates-and-key-assumptions.xlsx

Devine-Wright, P., Devine-Wright, H., & Cowell, R. (2015). What do we know about overcoming barriers to siting energy infrastructure in local areas?

Ejdemo, T., Söderholm, P. (2015). Wind power, regional development and benefit-sharing: The case of Northern Sweden., Renewable and Sustainable Energy Reviews.

Égré, D., Roquet, V., & Durocher, C. (2007). Monetary benefit sharing from dams: A few examples of financial partnerships with Indigenous communities in Québec (Canada).

Energy UK. 2024). Energy in Action: Community benefits from local infrastructure.

Glasson, J. (2020). Community Benefits and UK Offshore Wind Farms: Evolving Convergence in a Divergent Practice.

Klain, S.C., Satterfield, T., MacDonald, S., Battista, N., Chan, K.M.A. (2017). Will communities “open-up” to offshore wind? Lessons learned from New England islands in the United States.

Kerr, S. (2018). Community benefits schemes – Fair shares or token gestures?

Kerr, S., Johnson, K., & Weir, S. (2017). Understanding community benefit payments from renewable energy development. International Centre for Island Technology, Heriot Watt University.

Lane, T., & Hicks, J. (2019). A Guide to benefit sharing options for renewable energy projects. Akin Consulting; Community Power Agency.

le Maitre, J. (2024). Price or public participation? Community benefits for onshore wind in Ireland, Denmark, Germany and the United Kingdom.

Local Energy Scotland (n.d.). Annual community benefits from Scotland’s renewables reach £30 million. Local Energy Scotland website. Link: https://localenergy.scot/annual-community-benefits-from-scotlands-renewables-reach-30-million/

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Munday, M., Bristow, G., & Cowell, R. (2011). Wind farms in rural areas: How far do community benefits from wind farms represent a local economic development opportunity?

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Appendices

Appendix A – Methodology

Evidence review

Aims and objectives

The aims of the evidence review were to:

• Explore best practice on community benefits in the UK and internationally in relation to renewable energy technologies.
• Explore how community benefit schemes operate and examine their funding arrangements in the UK and internationally.
• Provide examples of where community benefits have been mandated and what impact this has had on industry, communities and the delivery of renewable energy technologies.
• Inform the socio-economic analysis in terms of identifying key parameters and contexts that impact the propensity to supply community benefits at varying scales.
• Identify data sources for the socio-economic analysis.

Defining the research questions

To ensure the evidence review is useful in summarising best practises and informing the socio-economic analysis the following research questions were defined:

• Research Question 1 – What is the best practice on community benefits from onshore and offshore renewable energy technologies internationally?
• Research Question 2 – How does the UK differ from international counterparts on the processes on the provision of community benefits? How does this impact the level of community benefits?
• Research Question 3 – Which (if any) countries mandate community benefits as part of net zero energy infrastructure construction? What impact has this had on the provision of community benefits? What impact has this had on communities and the delivery of net zero energy policies?
• Additional Scoping – What data is available on the levels of community benefits, and their corresponding technologies/market maturities/technology maturity and other hypothesised parameters which influence the provision of community benefits?

Scope of the literature search

The literature search included the identification of relevant sources from:

• Existing research into/evaluations of community benefit schemes
• Academic literature
• Grey literature
• Policy documents
• Media publications

The search for literature was primarily done through using Google and Google Scholar but also used sources such as JSTOR, Scopus, and organisational websites where necessary. Whilst we did not take a strict view on the geographical scope of our search, we favoured countries which are contextually similar to the UK (European countries, US, Australia) as it is likely these findings will be more relevant to the UK.

We explored literature relevant to onshore and offshore renewable energy technologies. This included, but was not limited to, wind, solar, hydro, wave, thermal, pumped hydro storage, bioenergy, battery storage, hydrogen, Negative Emission Technologies (NETs) and transmission infrastructure. The ability to look at these internationally was dependent on the context and energy mix of the countries in question. It was decided that it would also be useful to assess levels of community benefits for technologies which may be emerging in the UK but are more established elsewhere, bringing in the Three Horizons approach featured in the proposal.

Search Terms

Some initial search terms for covering the aforementioned specifications and research questions were developed and are presented in the table below:

Prioritisation approach

A long list of 86 sources were initially identified which were then prioritised using the prioritisation criteria set out below:

• Based on existing evidence: Does the document focus on existing practice/examples of renewable projects/developments?
• Focus on community benefits: Is the main focus of the document around the provision of community benefits (as opposed to for e.g. broader discussions of social acceptability of renewable energy developments OR community engagement)?
• Policy guidance: Does the document include policy recommendations/best practice guidance/reflections on lessons learned?
• Geographical scope: Does the geographical scope of the document include Europe, the UK or US?
• Peer reviewed / grey literature: Peer reviewed sources were prioritised over grey literature sources.

Additional considerations:

• Ensuring the inclusion of evidence on a wide spread of renewable technologies.
• Ensuring the inclusion of evidence from both voluntary and mandatory community benefits schemes.
• Ensuring the inclusion of evidence from a wide spread of types of community benefits.

Additional sources were added to the short-list of literature as suggested by Scottish Government and stakeholders in the scoping interviews. A total of 35 sources were reviewed in-depth. The final list of literature sources reviewed included 12 peer reviewed academic papers, 20 reports, 2 guidance documents from grey literature (e.g., renewable energy developers, private consultancies) and 1 policy document. The publication years of the reviewed documents ranges from 2011 to 2024, with 22 documents from the last 5 years.

Evidence extraction

The prioritised literature sources were then reviewed and findings relevant to the research questions were extracted into an excel sheet. Ipsos Facto, a Large Language Model, was used to assist with identifying and summarising relevant data.

Scoping interviews

In parallel to the evidence, we conducted four in-depth scoping interviews with industry bodies, trade associations, and members of developer groups to enhance the findings from the evidence review.

The aim of these interviews was twofold:

• to understand their views on different types of community benefits and their perceptions of current / best practice arrangements related to community benefits;
• to explore options for sourcing data from the industry, including the types of information they think businesses will / will not be prepared to share with us.

Learnings from the scoping interviews were used specifically to inform the design of the subsequent stakeholder engagement and framework development.

Developer interviews

In-depth interviews were conducted with 21 industry developers. Interviewees covered a range of technologies including onshore wind (7), offshore wind (7), solar PV (5), battery storage (6), grid stability (1), hydro (3), pumped hydro storage (3), hydrogen (6 including 2 green hydrogen) and carbon capture, utilisation and storage (2). Among interviewees, 11 were mostly multi-technologies developers and 10 were single-technology developers.

The objectives of the interviews were threefold:

1. To gather qualitative data on the types of community benefits they have delivered/plan to deliver, views on current arrangement for community benefits and potential different approaches (including mandating for onshore), and what factors have contributed to the provision/ success of their community benefits (i.e. to help inform what parameters are most important in informing potential future community benefits). This will help contextualise the socio-economic analysis and the findings in the report.
2. To gather quantitative data that we will then use in our analysis, using the parameters set out in the framework (these will be developed further based on CXC/SG feedback). This will include information such as the cost of developing the project(s), value of community benefits, proportion of those values in comparison with turnover/profit, employment impacts etc.
3. To help reframe/revise the socio-economic analysis framework as required, based on their views on what parameters/variables are important
4. Ahead of the interview, stakeholders were also requested to complete a ‘Data request sheet’ that aimed to gather data for the socio-economic analysis (see below).

Framework development

The development of the framework to assess the influence of various parameters on community benefits involved a systematic approach following stakeholder interviews. Each initial parameter underwent a comprehensive evaluation to determine the feasibility of its measurement and potential impact on community benefit commitments.

• Assessment of measurement challenges. Initially, each parameter was scrutinised to identify any inherent challenges or limitations in its measurement. This involved examining the complexity, availability of data, and any factors that could hinder accurate quantification.
• Identification of pre-existing measures. For parameters where it was determined that measurement challenges were minimal or non-existent, existing methodologies and measures were sought. This step involved a thorough review of established metrics and tools already in use.
• Development of proxy measures. In cases where no established measures were applicable, proxy measures were devised. This involved identifying the closest available data that could serve as a stand-in to approximate the parameter’s influence on community benefits. These proxies were selected based on their relevance and potential to offer meaningful insights.

Throughout this process, each parameter’s potential to influence community benefits was evaluated. This iterative methodology ensured a robust and nuanced framework, capable of effectively guiding future assessments and decisions concerning community benefit commitments.

Socio-economic analysis

To illustrate the application of the framework, a socio-economic analysis was conducted using a sample dataset of renewable energy projects. This analysis examined the relationship between the parameters detailed in Section 5 and the levels of community benefits, employing the methodologies outlined in the framework.

The analysis focuses on parameters deemed feasible to measure with available methods, specifically revenue and costs, along with technology type. Technology type was used as a proxy for technology maturity, given the current uniformity of maturity levels within each technology. The analysis relied on data from the Community Benefits Register Database, supplemented by additional information obtained through desk research.

For this analysis, the scope included onshore wind, offshore wind, and hydro technologies. These were chosen based on their data availability and relevance to the parameters evaluated.

Appendix B Examples of community benefit-sharing initiatives

Table 2 Examples of community benefit-sharing initiatives and related guidance for renewable technologies in selected European countries (from O San Martin et al. (2022)

Appendix C Socio-economic analysis results

To demonstrate how the framework could be used in future, socio-economic analysis was carried out based on a sample of data from net zero energy projects. This analysis explores the relationship between the parameters outlined in chapter 4 and the levels of community benefits, using the methods outlined in the framework.

The parameters in scope of this analysis are restricted to those which have been deemed feasible to measure and for which a suitable method to measure them has been identified These include revenue and costs, as well as technology type (which serves as a proxy for technology maturity, as maturity levels do not vary within technologies currently). It should be noted that this analysis is based on data available from the Community Benefits Register Database, supplemented with additional data sourced through desk research. Due to the data sources available, it only includes onshore wind, offshore wind and hydro technologies.

The subsequent analysis in this chapter presents the relationships between the measurable parameters for which data is available and the level of community benefits.

Key findings

• Industry alignment and policy influence. Many onshore wind and hydro projects in Scotland are clustering around the recommended annual £5,000 per MW capacity for community benefits for onshore technologies. However, a significant number of onshore wind and hydro projects (more than half of those analysed in the available dataset) commit less than the recommended amount.
• Revenue-benefit correlation. A positive correlation exists between gross project revenue and total community benefit commitments, with larger projects providing bigger packages. However, this relationship weakens for high-revenue projects, suggesting a potential plateau effect.
• Costs and benefit packages. There is a positive correlation between total costs and total community benefit packages. For projects costing less than £25 million, when comparing onshore wind and hydropower projects of the same energy capacity and with equivalent community benefit budgets (£5,000 per MW annually), onshore wind offers greater community benefits per pound spent on energy production.

Analysis of community benefit commitments

Many onshore wind and hydro projects in Scotland are aligning with the recommended community benefits package of £5,000 per MW capacity. The clustering of commitments around the recommended amount suggests that policy guidelines are influencing industry behaviour, but full compliance among onshore projects has not yet been achieved. This is observed in Figure 1 by the number of projects committing less than the recommended amount. Of the 282 onshore wind and hydro projects analysed, 177 were committing less than the recommend amount.

There exists a small but notable group of projects that have committed to providing community benefits from onshore renewable energy developments above the recommended £5,000 per MW capacity. These projects may be setting new benchmarks for corporate social responsibility. The strong concentration around the £5,000 figure could indicate an opportunity for standardising community benefit packages across the industry, potentially simplifying expectations for both developers and communities.

Figure 1 Distribution of Annual Community Benefit Commitments per MW – Onshore Projects

Source: Community Benefits Register Database

Figure 2 below illustrates where most of the data points are concentrated and the variation in the data. There are distinct patterns in community benefit commitments across the two different onshore renewable technologies shown. Figure 2 shows that hydro projects commitments range between £456 and £5,000 per MW per year, while onshore wind commitments range between £60-£20,000 (the upper end of this range is not visible in Figure 2 below as this distorted the shape and scales of the figure).

There is a concentration of commitments around the £5,000 figure for both hydro and onshore wind which aligns with the recommended amount (as demonstrated by the width of the violin plot), indicating a level of industry-wide acceptance of this guideline for land-based projects.

Figure 2 Distribution of Annual Community Benefit Commitments per MW by Onshore Technology

Source: Community Benefits Register Database

Figure 3 below shows the distribution of community benefit commitments among offshore projects. It should be noted that there was very low coverage of offshore wind projects captured in the register, and hence efforts were made to manually collect benefits data through desk-based research. This may have resulted in some discrepancies in actual provision versus what projects would have reported through the register. Figure 3 shows offshore wind projects notably committing lower amounts compared to onshore wind and hydro projects, with a range between c.£20-£2,000 per MW per year. It is acknowledged here that this analysis is based on 21 projects out of a possible 47 operational offshore wind projects in the UK^[55] and therefore figures should be treated with caution.

Figure 3 Distribution of Annual Community Benefit Commitments per MW – Offshore Projects

Source: desk research

There are several reasons why offshore wind projects might be committing lower amounts than their onshore counterparts. Most importantly, onshore renewable energy projects in Scotland are encouraged to offer community benefits, typically around £5,000 per megawatt of installed capacity annually. This is a voluntary guideline, not a requirement, specifically for onshore projects, and does not apply to offshore projects. Beyond this, offshore wind farms, being located further from communities, might be perceived as having less direct impact on local populations, potentially justifying lower community benefit packages. The offshore wind sector in Scotland is also at an earlier stage of development compared to onshore technologies, with community benefit standards still being defined. This technological and market immaturity means standards for community benefits are still evolving within this sector. In contrast, onshore wind technologies are more established and benefit from years of development and market experience. The advanced state of onshore wind technology may allow for greater efficiency and cost reduction, enabling more substantial community support relative to their offshore counterparts. Moreover, the scale of offshore wind projects may mean that while there are lower per-MW commitments, the overall total community benefits package may still be substantial.

Analysis of community benefit parameters and their impact

Revenue and profit

Figure 4 below illustrates the relationship between estimated gross revenue and total community benefit commitments over the project lifetime. The relationship is split and visualised by revenue levels due to the variation in the strength of the relationship as revenue changes. Blue dots represent projects that have committed £5,000 per MW per year, while red dots represent any figure other than the recommended £5,000 per MW. There is a clear positive correlation between gross project revenue and total community benefit commitments across all renewable energy projects in Scotland. This suggests that as projects become more financially substantial, they tend to provide larger community benefit packages. As project size increases in revenue terms, there is a widening range of community benefit amounts. This indicates that larger projects have more diverse approaches to community support. The relationship between gross revenue and community benefits appears to weaken for larger revenue projects. This suggests a potential plateau effect where community benefit increases do not keep pace proportionally with revenue growth beyond a certain point.

Small (under £35m gross revenue) and medium-sized (£25-250m gross revenue) projects frequently demonstrate commitment to the recommended £5,000 per MW amount, suggesting strong guideline adherence among projects of these scales. Across these sized projects, there are few instances of commitments exceeding the recommended amount relative to their revenue, suggesting a general reluctance to exceed standard guidelines.

Figure 4 Community Benefits Package by Gross Revenue Bucket (Under £25M, £25M-£250M and £250M+ Gross Revenue)

Source: See appendix F (Recommended data sources)

Deployment and Operating Costs

Figure 5 below shows the relationship between estimated total cost of production, expressed as the average cost of producing one unit of energy (LCOE – £/MWh) multiplied by total expected production over the project lifetime, and total community benefit commitments over the project lifetime. As above, the relationship is split and visualised by total cost of production levels due to the variation in the strength of the relationship as total cost changes. There is a positive correlation between total cost of production and total community benefit packages across all project sizes, suggesting that as total costs increase, as does the size of the overall commitment to community benefits. The correlation between total cost and total community benefit are relatively strong (Pearson correlation coefficient^[56] = 0.56) at lower total cost levels (under £25M total cost). This increases to 0.62 for mid-sized projects (£25-250M total cost). However above £250M total costs, there is no correlation (Pearson correlation coefficient=-0.002), indicating that total cost plays less of a role in determining community benefits at large cost levels.

While this may appear contrary to the views of developers shown earlier (i.e. those who said that high costs can impact on financial viability and therefore their ability to offer community benefits) it should be noted that this data analysis is based only on projects that were already providing monetary community benefits. It excludes those that had not provided any benefits. It can therefore be assumed that the dataset excludes those projects that were deemed not financially viable enough to enable community benefit provision.

This analysis goes further to explore whether there are any differences by technology class within onshore projects only (offshore projects have been removed at this stage as the recommended £5,000/MW applies only to onshore technologies). In order to do so, it is important to control for project size (as measured by MW capacity), so as not to produce spurious results. Figure 6 illustrates how many pounds (£) are allocated to community benefits for every pound (£) spent producing energy, categorised by the project’s size in capacity (MW). Blue dots represent projects that have committed less than the recommended £5,000 per MW per year, while green dots represent projects that have committed more than the recommended amount and red dots represent project that have committed the recommended £5,000 per MW. For projects with total production costs under £25 million, when comparing hydro and onshore wind projects of the same capacity that both allocate £5,000 per MW annually to community benefits, onshore wind projects are actually providing more community benefits per pound (£) spent on energy production than hydro projects.

Figure 5 Community Benefits Package by Total Cost of Production Bucket (Under £25M, £25M-£250M and £250M+ Total Cost)

Source: See appendix F (Recommended data sources)

Figure 6 Community Benefits Package by Total Cost of Production Bucket (Under £25M, £25M-£250M and £250M+ Total Cost)

Source: See appendix F (Recommended data sources)

Appendix D Methodologies for estimating revenue and costs

Project Revenue

Simplified Annual Revenue Estimation – Generation Projects

The fundamental formula for estimating annual revenue is as follows:

Estimated Revenue = Expected Generation (MWh) * Electricity Price (£/MWh), where

Expected Generation (MWh) = Capacity (MW) * Capacity Factor* Hours in a year

Breaking down these components:

• Installed Capacity (MW): This represents the maximum power output of the project under ideal conditions. This data is readily available from the Renewable Energy Planning Database (REPD).
• Capacity Factor: This represents the actual output of a project as a percentage of its maximum potential output over a specific period. Historical capacity factors for certain technologies (onshore wind, offshore wind, hydro, landfill gas, and sewage sludge digestion) in Scotland can be found in the Energy Trends: UK Renewables publications^[57].
  • Addressing Missing Capacity Factors: For technologies where Scotland-specific capacity factors are unavailable (e.g., solar PV, tidal, wave, biomass), several approaches can be used:
    • UK-wide Proxies: Use UK average capacity factors as a starting point, acknowledging this as a limitation and potential source of error.
    • Technology-Specific Adjustments: Adjust UK proxies based on technology and location characteristics. For example, solar PV capacity factors are influenced by latitude and solar irradiance. Tools like PVGIS can provide location-specific solar irradiance data to refine estimates (this approach is out of scope for the analysis in this study).
• Average Annual Electricity Price (£/MWh): This represents the average price received for each MWh of electricity generated over a year. Given the difficulty of obtaining project-specific PPA data, the wholesale market price serves as a practical proxy.
  • Wholesale Price Data Sources: While real-time wholesale price data requires plugging into Elexon’s BMRS API, a simplified approach for this framework should entail using Ofgem’s published weekly wholesale day-ahead price data^[58] to calculate annual averages. These are GB-wide averages, and hence regional variations should be recognised as a limitation.
  • Simplified CfD Approach (for CfD-supported projects): For projects under a Contract for Difference (CfD) the strike price is a guaranteed price. This figure is a conservative estimate of returns, as actual revenue could be higher if market prices exceed the strike price. CfD data is available from the Low Carbon Contracts Company (LCCC).

Estimating Future Revenue (also applicable for projects not yet operational) – Generation Projects

For revenue in future years, or for projects under development or construction, estimating future revenue requires additional considerations:

• Project Lifetime Assumption: Specify a reasonable assumed operational lifetime for the technology (e.g., 25 years for offshore wind, 20-25 years for solar PV). This assumption directly impacts total revenue calculations.
• Future Capacity Factor Estimation: Project future capacity factors based on recent trends and technological advancements. If historical capacity factor data for the specific technology in Scotland (or a similar region) is available, this trend should be analysed over the past years.^[59] This trend should be extrapolated outward to estimate future capacity factors. For less established technologies with limited historical data, the technology’s maturity should be considered. Rapidly evolving technologies may see more significant performance improvements expected while more mature technologies might expect to see more stable future performance anticipated. For example, floating offshore wind might be expected to see larger capacity factor gains in the coming years compared to a more established technology like onshore wind.
• Future Electricity Price Estimation: Given the volatility of electricity markets, projecting future prices is challenging. For projects supported by a Contract for Difference (CfD), the strike price offers a guaranteed future revenue stream and can be used as a conservative estimate. For non-CfD projects, where future revenue is directly exposed to market price fluctuations, a simplified approach involves using the average annual CfD strike price for the corresponding technology in each future year. However, it’s essential to acknowledge that:
  • CfD strike prices are influenced by auction dynamics and may not perfectly represent the market value of electricity from non-CfD projects.
  • Not all technologies are represented in CfD auctions.
  • Using CfD strike prices as proxies across all non-CfD projects might result in a somewhat conservative revenue estimate, as market prices could exceed the strike price in some years.

Prices beyond the latest future year reported in the CfD auction reports are set at the price in the latest year for the respective technology. For example, if CfD auction strike prices are set for the year 2027, the strike price in all future years will be set at the prices in 2027 for that technology. It is acknowledged these prices are unrealistic, however, they serve as the most appropriate benchmark against which to extrapolate.

• Discounting Future Cash Flows: To compare projects and scenarios, discount future revenue streams to their present value using an appropriate discount rate that reflects project risk. We propose using the technology-specific discount rate of 10% used by DESNZ in their Levelised Cost of Electricity (LCOE) methodology documents.

Total Cost of Production Calculation

Total Cost of Production Calculation – Generation Projects

Estimating the total lifetime cost of production across the range of projects in scope requires a consistent and transparent method to apply cost assumptions across different generation technologies. To support this, we use benchmark Levelised Cost of Electricity (LCOE) estimates published by DESNZ.

DESNZ’s LCOE values represent the average lifetime cost (£/MWh) of generating electricity for each technology type. These figures include all relevant capital, operational, fuel, and decommissioning costs, spread over the expected lifetime electricity output of a project. As such, LCOE is a useful and well-recognised benchmark for comparing the cost-effectiveness of electricity generation technologies in the UK.

Importantly, we are not re-estimating or recalculating LCOE. Instead, we are using DESNZ’s published LCOE values as input parameters in our framework to estimate total cost of production across different project configurations. Specifically, we apply the LCOE estimates to the expected energy output of each project to calculate a total cost figure. This calculation can be expressed as:

Total Cost of Production (£) = LCOE (£/MWh) x (Installed Capacity (MW) x Load Factor x Annual Operating Hours x Project Lifetime (years))

This approach allows us to derive a consistent estimate of total production cost, using technology-specific LCOE values as cost rates, scaled by the expected energy output of each project over its lifetime.

The process for estimating total cost of production is as follows:

• Technology categorisation: Categorise REPD projects to align with the technology categories used in the UK Government’s LCOE estimates file. This may involve mapping project types to the closest matching category in the government data.
• Energy Output Calculation: Estimate the annual energy output (MWh) for each project based on its capacity and typical capacity factors for the relevant technology.
• Total calculation: Using the scaled cost components and estimated energy output, we will calculate the total cost for each project using the formula. It’s important to note that the UK Government’s LCOE estimates are provided for projects with commissioning dates in 2025, 2030, 2035, and 2040. Therefore, our total cost calculations will need to be based on the estimate that most closely matches each project’s expected commissioning date. We will assign each project to the nearest available estimate year based on its planned commissioning date.
• Inflation-adjustment: Furthermore, all costs in the UK Government’s estimates are reported in 2021 prices. To ensure consistency and accurate comparisons across projects with varying commissioning dates, we adjust these figures to a common base year using HM Treasury GDP deflators. These temporal adjustments will help ensure that our total cost calculations accurately reflect the economic conditions and technological advancements expected at the time of each project’s commissioning, within the constraints of the available data.

Appendix E Socio-economic scoring mechanisms

Table 3 NASA Technology Readiness Levels

Table 4 IEA Technology Guide Technology Maturity Scale

Table 5 Market Maturity Scale

Appendix F Recommended data sources

The following below provides a summary of the key data sources currently available to measure framework parameters. However, these are not complete and additional work is required to fill gaps.

How to cite this publication:

Mulholland, C., Jones, R., Tapie, N. and Stow, C. ‘Renewable energy technologies and community benefits’, ClimateXChange. http://dx.doi.org/10.7488/era/6396 

© The University of Edinburgh, 2025
Prepared by Ipsos 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 as at the date of the report, 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.

This work was supported by the Rural and Environment Science and Analytical Services Division of the Scottish Government (CoE – CXC).

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1. 
   

   See Community benefits and shared ownership for low carbon energy infrastructure: working paper (accessible webpage) – GOV.UK ↑

   
   
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   Scottish Government (2020) ↑

   
   
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   Scottish Government (2024) ↑

   
   
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   Scottish Government (2019) ↑

   
   
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   Scottish Government (2018) ↑

   
   
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   Scottish Government (2023) ↑

   
   
7. 
   

   Community benefit funds typically mean that developers will voluntarily contribute a certain amount of funding to local communities. In some cases, the level of funding is linked to the amount of installed capacity of the project or the amount of energy produced. ↑

   
   
8. 
   

   Kerr et al (2017), Anchustegui (2021), Kerr & Weir (2018), O San Martin et al (2022), Scottish Government (2022), Scottish Government (2019), Scottish Government (2018) ↑

   
   
9. 
   

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10. 
    

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11. 
    

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12. 
    

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13. 
    

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14. 
    

    In the reviewed literature, shared ownership was a common practice in countries outside the UK, notably in Germany and Denmark. However, this is not outlined here as shared ownership is not part of the Scottish Government’s definition of community benefits. ↑

    
    
15. 
    

    le Maitre, 2024; Toledano, et al., 2023; O San Martin, et al., 2022; ↑

    
    
16. 
    

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17. 
    

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18. 
    

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19. 
    

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20. 
    

    Regen, 2022 ↑

    
    
21. 
    

    van den Berg & Tempels (2022); Glasson (2020) ↑

    
    
22. 
    

    Kerr & Weir (2018), Scottish Government (2022) ↑

    
    
23. 
    

    le Maitre (2024) ↑

    
    
24. 
    

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25. 
    

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26. 
    

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27. 
    

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28. 
    

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29. 
    

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30. 
    

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31. 
    

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32. 
    

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33. 
    

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34. 
    

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35. 
    

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36. 
    

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37. 
    

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38. 
    

    Glasson (2020), Manitius (2023), Arsenova & Wlokas (2019), BiGGAR Economics (2024a), BiGGAR Economics (2024b), Toledano et al. (2023) ↑

    
    
39. 
    

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40. 
    

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41. 
    

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42. 
    

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43. 
    

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44. 
    

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45. 
    

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46. 
    

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47. 
    

    Herrera (2021) ↑

    
    
48. 
    

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49. 
    

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50. 
    

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51. 
    

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52. 
    

    Kerr et al (2017); le Maitre (2024) ↑

    
    
53. 
    

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54. 
    

    BiGGAR Economics (2023) ↑

    
    
55. 
    

    Four operational offshore wind projects were in Scotland, two in Wales and fifteen in England. ↑

    
    
56. 
    

    The Pearson correlation coefficient measures how strongly two variables are linearly related, ranging from -1 (perfect negative correlation) to 1 (perfect positive correlation), with 0 indicating no linear relationship. ↑

    
    
57. 
    

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58. 
    

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59. 
    

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As part of its commitment to achieving net zero by 2045, the Scottish Government has ambitions for Scotland to become a major exporter of low-carbon hydrogen and hydrogen derivatives and products (HDPs).

Hydrogen can be produced using electrolysis, a process which involves splitting water into hydrogen and oxygen. When this process is performed using only renewable sources of electricity, the hydrogen produced is known as green hydrogen.

This study explores Scotland’s capabilities of producing green hydrogen and developing the HDP sector, identifying opportunities and barriers it may face in scaling it up. It also aims to understand the role different regions of Scotland can play in enabling the growth of these sectors.

Findings

Scotland’s abundant access to renewable energy, geographic proximity to the EU, skilled workforce and a favourable external policy landscape are major strengths that can enable growth in the hydrogen and HDP sectors. However, there are potential weaknesses and barriers too. Producing renewable electricity, a major cost source for producing green hydrogen, is currently relatively expensive in Scotland, with prices around 70% higher than the average of EU and G7 countries.

Supply chain capabilities and addressable market demand

Following a systematic comparison of the supply chain capabilities of 14 potential hydrogen hubs identified by the Scottish Government, Aberdeen ranked the highest in many metrics, followed by Cromarty and Ayrshire.

The report also assessed the addressable market demand for HDPs. Roughly 97% of all HDP demand comes from the aviation and maritime sectors and Grangemouth was estimated to have the biggest market demand for both.

Co-locating demand and supply will enable the early scaling of Scotland’s hydrogen and HDP sectors as national network infrastructure is developed. Analysis of both supply and demand found that with the presence of a large chemicals industry and a major airport, Grangemouth outperforms all other hubs. Despite relative strengths in supply chain capability, Aberdeen is not the optimal region for co-locating supply with demand opportunities.

Policy gaps

Analysis of the policy landscape in the UK, the EU and Scotland suggests a number of potential approaches to help develop the hydrogen and HDP sectors. Scotland’s abundant access to renewable energy, strong workforce capabilities and demand potential can facilitate vibrant hydrogen and HDP sectors. However, Scotland will need to address issues such as:

• the high cost of electricity generation;
• a more sophisticated planning regime that considers both site demand and supply in order to optimise co-location strategies.

Working with the UK and foreign governments to capitalise on export opportunities will allow Scotland to expand its potential market size.

Cross-hub development

Although Aberdeen and Grangemouth stand out as having relative strengths in relation to supply chain capabilities and market demand, there are strengths and capabilities across the other potential hubs. Cromarty and Ayrshire offer strong supply chain capabilities. Glasgow and Fife present significant demand opportunities. The Western Isles and Argyll and Islands may require targeted support to enhance their supply chain capabilities, while the Scottish Borders may need support in developing greater regulatory experience.

This diversity points to the importance of a cross-hub approach, in addition to co-locating demand with supply. By balancing cross-hub collaboration with localised development, Scotland can maximise the potential of its hydrogen economy, driving the sector’s long-term growth and resilience.

For further information, please read the report.

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

Research completed: April 2025

DOI: http://dx.doi.org/10.7488/era/6397

Executive summary

Aims

The Scottish Government is committed to achieving net zero emissions by 2045, five years ahead of the UK’s target. Scotland also aims to become a major exporter of low carbon hydrogen derivatives and products (HDPs) and has access to the abundant renewable energy necessary for their production. Hydrogen derivatives are chemicals produced from hydrogen that can more easily be stored and transported and then converted back to hydrogen for later use. Examples include ammonia and methanol. Hydrogen products, such as sustainable aviation fuels (SAFs), do not need a further conversion process and are used for a range of applications.

Hydrogen can be produced using electrolysis, a process which involves splitting water into hydrogen and oxygen. When this process is performed using only renewable sources of electricity, the hydrogen produced can be deemed as green hydrogen.

As green hydrogen supply is crucial for the development of HDP production, this study explores Scotland’s strengths and weaknesses in developing both the green hydrogen and HDP sectors. Throughout this study, the term “hydrogen and HDP sector” is used to include green hydrogen and HDPs produced using that green hydrogen.

This study analyses Scotland’s supply chain capabilities in producing HDPs and identifies opportunities and barriers it may face in scaling up the hydrogen and HDP sectors. It also aims to understand the role different regions of Scotland can play in enabling the growth of these sectors.

Findings

Scotland’s abundant access to renewable energy, geographic proximity to the EU, skilled workforce and a favourable external policy landscape are major strengths that can enable growth in the hydrogen and HDP sectors. However, there are potential weaknesses and barriers too. Producing renewable electricity, a major cost source for producing green hydrogen, is currently relatively expensive in Scotland, with prices around 70% higher than the average of EU and G7 countries.

Supply chain capabilities

The Scottish Government’s Hydrogen Action Plan identified 14 hydrogen hubs. This report systematically compared the supply chain capabilities of each for producing HDPs. Hubs were assessed on:

• Availability of feedstock (i.e., production source material)
• Economic factors from co-located industries
• Workforce and skills
• Infrastructure,
• Local policy and planning support, and
• Co-location with innovation institutions

For comparison, the Duisburg region of Germany was assessed against the same metrics, as a potential competitor to Scottish hubs.

Aberdeen ranked the highest in many metrics, followed by Cromarty and Ayrshire. The Duisburg hub also scored highly on several metrics. The aim was not to find a single best hub. Aberdeen’s high score suggests that it is currently relatively well-developed against the supply chain metrics, it does not suggest that this is the sole hub suitable for developing Scotland’s hydrogen and HDP sectors.

Addressable market demand

The report estimated the addressable market demand for HDPs in each hub. The HDPs considered were ammonia and e-methanol for the maritime sector, ammonia-based fertiliser for the agriculture sector, e-methanol feedstock for the chemical sector, and SAF for aviation.

The addressable demand for all HDPs in all the sectors is around 35 TWh. Roughly 97% of this comes from just the aviation and maritime sectors. Grangemouth is estimated to have the biggest market for HDPs in both sectors.

Co-locating demand and supply

Co-locating demand and supply will enable the early scaling of Scotland’s hydrogen and HDP sectors as national network infrastructure is developed. Aberdeen and Grangemouth both stand out as key hubs for the development of Scotland’s HDP economy. Analysis of supply and demand found that with the presence of a large chemicals industry and a major airport, Grangemouth outperforms all other hubs.

Despite relative strengths in supply chain capability, Aberdeen is not the optimal region for co-locating supply with demand opportunities because the maximum demand potential is higher in Grangemouth.

There are significant hazards associated with HDPs bringing associated regulatory requirements. Analysis of current Control of Major Accidents and Hazards (COMAH) site locations provides insight into the infrastructure and the expertise needed to handle HDPs safely. Fife, Glasgow, Moray and Grangemouth hubs have the most COMAH sites, bringing relatively strong experience in this regulatory environment.

Policy gaps

Analysis of the policy landscape in the UK, the EU and Scotland suggests a number of potential approaches to help develop the hydrogen and HDP sectors. Scotland’s abundant access to renewable energy, strong workforce capabilities and demand potential can facilitate a vibrant hydrogen and HDP sectors. However, Scotland will need to address issues such as:

• the high cost of electricity generation;
• a more sophisticated planning regime that considers both site demand and supply in order to optimise co-location strategies.

Working with the UK and foreign governments to capitalise on export opportunities will allow Scotland to expand its potential market size.

Conclusions

Hub development requires both a cross-hub approach and strategic co-location of regional supply and demand. Individual hubs should not be considered in isolation. Particular hubs score relatively highly but this does not preclude a very significant role for other hubs within the overall hydrogen and HDP sectors.

Aberdeen and Grangemouth stand out as having relative strengths in relation to co-location of supply chain capabilities with demand. Cromarty and Ayrshire offer strong supply chain capabilities. Glasgow and Fife present significant demand opportunities. The Western Isles and Argyll and Islands may require targeted support to enhance their supply chain capabilities. The Scottish Borders may need support in developing greater regulatory experience.

By balancing cross-hub collaboration with localised development, Scotland can maximise the potential of its hydrogen economy, driving the sector’s long-term growth and resilience.

Glossary / Abbreviations

Abbreviations

Glossary of units

Introduction

Scotland has set an ambitious target to reach net zero by 2045. To be able to achieve its targets, Scotland will have to rapidly decarbonise its economy. The Scottish Government is exploring options to use hydrogen to decarbonise certain sectors and to develop current HDP capabilities in support of climate goals. Scotland ultimately aims to produce 5 GW of low-carbon hydrogen by 2030 and 25 GW by 2045. In addition to reaching its net zero goals, the Scottish Government also aims to utilise these resources to capitalise on export and other economic opportunities. Green hydrogen is expected to be the dominant low carbon production method in Scotland. This study focuses solely on HDPs produced from green hydrogen, which are referred to as “HDPs” throughout this report.

In this study we aim to explore Scotland’s supply chain capabilities. To situate the need for this research, we conducted a review of existing literature (see Appendix A: Current state of play). Our review of the literature analyses the strengths that Scotland possesses to scale up its hydrogen and HDP sectors. It also details some of the biggest barriers that Scotland is likely to face. The review then focusses briefly on specific HDPs and their potential role in enabling Scotland’s transition to net zero.

We also analyse Scotland’s strengths and weaknesses in developing its capabilities. We focus on assessing the opportunities and challenges associated with exporting HDPs to the rest of the UK and the EU. Moreover, we aim to understand the role that different regions of Scotland can play in enabling the development of HDP production. We have identified 14 regional hydrogen hubs in Scotland from the Scottish Government’s Hydrogen Action Plan (2022), shown in Table 1. In addition to the Scottish hubs, the study also considers the Ruhr region of Germany as an alternative hub. Scotland is expected to export a significant amount of its green hydrogen produce to the EU. Therefore, the Ruhr region of Germany was considered as a potential alternative source of green hydrogen for the EU.

For each metric, we rank the hubs to analyse their relative strengths, before combining these rankings into a final capability score for each hub in Section 3.8. In this manner, we provide a balanced and quantitative assessment of the relative supply chain capabilities of Scotland’s hydrogen hubs. It is important to note that the purpose of this analysis is not to find the absolute “best” hydrogen hub in Scotland. By ranking the hubs in each metric, we have assessed their relative strengths and weaknesses.

In an international market, Scotland’s hubs will be competing with various other green hydrogen and HDP production areas. As Scotland aims to export to Europe, in particular Germany, it will have to compete with local European production (Scottish Government, 2024). Germany’s Ruhr region aspires to be the first model hydrogen region to accelerate the hydrogen sector in Europe (Hydrogen Metropole Ruhr, 2023). Hydrogen is already playing a role in developing HDP production in the region (Metropole Ruhr Business, 2025). One example is the Greenlyte’s project in Marl which is producing e-methanol from CO₂ and green hydrogen. In August 2025, this project secured a 7-figure e-methanol offtake agreement with Germany-based MB Energy, indicating substantial market interest for HDPs produced in the Ruhr region (Greenlyte, 2025). Given Ruhr’s strong ambitions, to evaluate Scotland’s competitiveness at the international level, we will compare the Scottish hubs with the hydrogen hub of Duisburg, situated in the Ruhr region.

In subsequent chapters, we analyse the supply chain capabilities of each hub in Scotland, addressable demand for various HDPs in different sectors, and the regulatory environment related to safety. The final chapter focusses on the wider policy landscape, analysing gaps and providing recommendations to policymakers.

Table 1: List of Scottish hubs and their corresponding local authorities.

Supply chain capabilities of Scotland’s hydrogen hubs

In this chapter, we investigate the relative supply chain capabilities of Scotland’s hydrogen hubs to produce HDPs. We have selected six capability groups for evaluation (shown in Table 2). These groups are broadly based on the six key advantages for hydrogen production identified in the Scottish Government’s Hydrogen Action Plan (2024). Certain capability groups, such as pipeline infrastructure, are highly dependent on future developments at a national and international level. The results from analysing all these capability groups will allow us to assess each hub’s intrinsic and long-term supply chain strengths that will enable the fast growth of the hydrogen and HDP sectors.

We have then broken down these groups further into assessment metrics in order to accurately evaluate the capability groups against available data. This analysis produces detailed hub differentiation to support actionable conclusions for policymakers. Table 2 shows each capability group and their associated metrics. Further information on metric methodology, sources and data is found in Appendix B.

Table 2: Capability groups and assessment metrics for evaluating the supply chain capabilities.

Feedstock and inputs

Renewable electricity and water are the two fundamental feedstocks for green hydrogen production. The availability of both can be seen to vary, by region. This is in contrast to the supply of nitrogen for e-ammonia or carbon dioxide for e-methanol, where both feedstocks are derived from air, via direct air capture and can therefore be assumed to be equally available to all hubs.

Maximum potential renewable power generation

Scotland’s abundant renewable energy resources are key to its net zero transition. In particular, the Scottish Government has identified Scotland’s extensive offshore wind resource as a considerable opportunity for green hydrogen production (Scottish Government, 2020). Under a business-as-usual scenario, installed offshore wind capacity is expected to rise from 3.4 GW in 2025 to 27 GW in 2045 (Scottish Government, 2020). Green Hydrogen production can support this growth by helping to overcome Scotland’s grid constraints.

The co-location of renewable energy generation and HDP production takes advantage of existing infrastructure, reduced electricity transmission costs and improved project economics. An example of co-location is Scottish Power’s planned 20 MW Whitelee Green Hydrogen Project near Glasgow (Scottish Power, 2024). The facility will be co-located with a 70 MW combined Solar and Battery Energy Storage Scheme. Adjacent is the 539 MW Whitelee Windfarm and substation.

We have analysed the maximum potential renewable power generation for each hub, based on the total current, planned and announced installed capacity of solar and wind power projects (DESNEZ, 2024; Offshore Wind Scotland, 2024). We scaled the resulting capacities by the appropriate load factor to determine the maximum potential renewable power generation (see Appendix B for load factors). For offshore wind, we assigned each project to the hub associated with its current or forecasted onshore landing point.

Figure 1: Maximum potential renewable power generation split by current and future (planned and announced) projects.

The order of hubs by maximum potential renewable power generation is shown in Figure 1. As shown from left to right, Aberdeen is ranked first and Duisburg, Germany is ranked last.

We can take several key insights from Figure 1:

• Access to future wind projects, particularly offshore wind, broadly determines which hubs have the most renewable power capability. Aberdeen, ranked first, accounts for around 50% of planned and announced offshore wind capacity among the Scottish hubs.
• Hubs with large future offshore wind projects – such as the announced ScotWind projects – lead the rankings (Offshore Wind Scotland, 2024). These hubs include Aberdeen, Cromarty and Moray.
• Grangemouth, with no current or future offshore wind capacity, ranks lowest among the Scottish hubs.
• As a densely populated hub, with no offshore wind, Duisburg ranks lowest overall.

Water availability

Sustainable water management is vital to balancing our water demand with environmental and ecological needs. Therefore, it is important to identify the water supply for hydrogen production early in the development process to ensure sufficient availability.

The electrolysis process requires large volumes of treated water, which is split to form hydrogen and oxygen. Reviewing the commercial electrolyser technologies, an estimated 10 litres of water is required per kilogram of green hydrogen produced (Ramboll, 2022). Water for green hydrogen production can be obtained from several sources, shown in Table 3:

Table 3: Sources of water for green hydrogen production (Ramboll, 2022).

Where possible a local water supply should be used for green hydrogen production, due to the cost of transporting water over long distances (Ramboll, 2022). Ramboll proposes that effluent should be the first water source considered as it does not compete with other sectors such as agriculture. Surface water, groundwater and potable water may be sourced from the mains water supply dependant on capacity and infrastructure availability. However, the use of potable water should be avoided where possible (Ramboll, 2022). While desalination has not been established for water supply in Scotland, the use of seawater may be an interesting option for the future hub development, particularly for island hubs which have less connectivity to mains infrastructure. However, for this analysis, we have focused on Scotland’s current water infrastructure capabilities from mains water supply and regional Scottish Water Wastewater Treatment Works.

In 2022, Ramboll, on behalf of SGN, investigated the water availability for green hydrogen production across Scotland (Ramboll, 2022). Drawing on Ramboll’s work, Table 4 shows the maximum green hydrogen production potential, based on water availability and the forecasted installed green hydrogen production capacity in 2045. We used these figures to assess water availability for the forecasted installed capacity in 2045. For Duisburg, we applied the same assumptions used for the Scottish hubs (Ramboll, 2022, pp. 26-27).

Table 4: Water availability ranking by hub

The relative water availability for hubs is shown in Table 4, from which we can take several key insights:

• Overall, water availability is unlikely to limit the deployment of forecasted green hydrogen installed capacity. However, future water abstraction may be limited by regulatory changes, land use restrictions, and competing demand.
• Shetland is ranked in last place as it is the only hub where forecasted green hydrogen production requires more water than is currently deliverable. This issue could be mitigated if desalination infrastructure is made available.
• Populous areas are more favourable for expanding green hydrogen production capacity based on water availability. These areas have greater effluent wastewater availability, which does not compete directly with other use cases. For example, Glasgow could potentially produce up to 203 GW of green hydrogen from effluent water. Orkney, in comparison, could only produce up to 0.03 GW.
• The island hubs (Western Isles, Orkney and Shetland) rank lowest. This is due to their limited freshwater supply and small population.

Economic output from relevant co-located industries

Gross Value Added of the energy sector

To evaluate the economic output from relevant co-located industries, we have compared the gross value added (GVA) of the energy sector in each hub. A high GVA signals that a region has a strong existing industrial base, infrastructure and workforce for the energy sector. This makes GVA a useful indicator of the investment attractiveness of establishing local hydrogen and HDP sectors.

Using the Scottish Government’s Industry Statistics, we have calculated the approximate gross value added of the energy industry for each hub in 2022 (Scottish Government, 2024). The definition of energy sector is based on Standard Industrial Classification (SIC) Codes 2007 and is outlined further in Appendix B. Generally, these SIC codes cover the following industries:

• Fossil fuel extraction and mining
• Manufacturing of petroleum products and other organic chemicals
• Energy supply e.g. electricity
• Water processing and supply
• Waste treatment and disposal
• Engineering and environmental consultancy

Figure 2: Estimated balanced GVA of the energy sector (2022).

The order of hubs by energy sector GVA is shown in Figure 2 from left to right. Aberdeen’s energy sector has the highest GVA at £25.9 billion in 2022; the Western Isles has the lowest, with a GVA of £16.8 million. Aberdeen, as the primary base of operations for the UK’s offshore oil and gas industry, is by far the major contributor to Scotland’s energy sector GVA (Port of Aberdeen, 2025).

For Duisburg, we conducted a separate analysis to allow comparison on a like-for-like basis using available data. Considering the Production Sector, as defined by SIC Codes 2007, Duisburg is ranked second after Aberdeen with a GVA of £4.15 billion (Länder, 2024; Office for National Statistics, 2024).

Workforce and skills

For this capability group, we have assessed the current workforce and the future workforce metrics for each hub. The expanding hydrogen and HDP sectors will demand a skilled and educated workforce. Scotland’s existing energy and engineering professionals are best positioned to make this transition, although not all will do so. To account for this unknown, we have evaluated future workforce requirements as well as the current transferable workforce.

Full time equivalent workers in energy and engineering

We have analysed the number of full-time equivalent (FTE) workers in these sectors (Skills Development Scotland, 2024). This will provide us with an indication of the relative workforce availability between the hubs.

Figure 3: Number of FTE workers in the energy and engineering sectors by hub

Figure 3 shows that Aberdeen has the most workers in energy and engineering with 71,100 FTEs; the Western Isles ranks lowest with only 400 FTEs. We can take several key insights from Figure 3:

• Aberdeen and Glasgow are the hubs with the largest transferable workforce. Among all the hubs, Aberdeen and Glasgow contain 70% of all FTE workers in energy and engineering.
• Skilled workforce availability may be a challenge for island hubs. There are only 1600 FTEs in energy and engineering across Shetland, Orkney and the Western Isles combined.

Future workforce requirements

We evaluated the hubs in terms of their future workforce requirements, analysing estimated demand for Scottish workers in the energy and engineering sectors. Labour forecasts can be divided into two categories: replacement demand and expansion demand. For this study, we have only considered expansion demand^[1].

Positive expansion demand represents increasing labour demand due to sector growth. Negative expansion demand suggests shrinking sectors, demanding less labour. The time period considered for this analysis was 2027-2034.

Hubs with higher expansion demand will see more competitive labour market conditions. Growing hydrogen and HDP sectors in such hubs can be expected to increase labour competition further. Hubs with negative expansion demand are expected to have less competitive labour market conditions in the future. Growing the HDP sector in such hubs will not exacerbate competition for skilled workers, as the number of jobs is likely to exceed the number of available workers.

Figure 4: Estimated expansion labour demand in energy and engineering sectors.

Figure 4 shows Aberdeen with the lowest expansion demand of -4,600 people. This means the engineering and energy sectors in Aberdeen will require 4,600 fewer workers in the period 2027-2034 compared to today. Glasgow, Fife, Ayrshire and Grangemouth follow with expansion demands between around -1,500 (Glasgow) and -700 (Grangemouth). These hubs are likely to have the least competitive labour market conditions in the future, implying less competition for workers in the growing hydrogen and HDP sectors. As Figure 4 shows, none of the hubs is forecast to have positive expansion demand: more additional workers are not expected to be needed in any hub. The labour market environment for engineering and energy jobs, within each of the hubs, appears to be favourable for growing Scotland’s hydrogen and HDP sectors.

It is worth reiterating that replacement demand has not been considered in this analysis. Therefore, it is important to understand that this analysis does not provide a full image of the future labour market for the hubs in these two sectors.

Infrastructure

Regional infrastructure is key for facilitating the storage, distribution and trade of green hydrogen to supply HDP production. In A Trading Nation – Realising Scotland’s Hydrogen Potential – A Plan for Exports, the Scottish Government identified ports, pipelines and large-scale storage as the three connectivity pillars required to enable the hydrogen and HDP sector’s growth (2024). Here, we investigate each hub’s relative strengths.

Large-scale storage capacity

Large-scale storage will be required to scale up hydrogen production and balance supply and demand. This scale of storage will likely be provided by underground geological storage, rather than aboveground storage which is constrained by land availability. There are several types of geological storage, which are described in Table 5.

Table 5: Types of geological storage for hydrogen and their technology readiness levels (ClimateXChange, 2023).

There are currently no projects to develop commercial geological hydrogen storage in Scotland. Moreover, apart from salt caverns, these technologies are still immature. So, we have assessed the technical geological storage capacity for each hub. For this, we have used available estimates from scientific literature. We assigned storage capacities to each hub based on their location or, if offshore, their likely terminal. The locations and total technical capacity for each storage technology is shown in Table 6.

Table 6: Technical capacity and locations for geological storage types in Scotland.

We scored the hubs based on their total geological storage capacity for hydrogen. We then adjusted these scores to account for the possibility of developing offshore salt caverns and planned pipeline connections to English salt caverns.

Figure 5: Large-scale storage capacity by hub.

Figure 5 shows the relative strength of hubs in terms of geological storage capacity. As shown from left to right, Aberdeen is ranked highest, and the Western Isles is ranked lowest. We can take several key insights from our analysis and the rankings in Figure 5:

• The most attractive hubs – Aberdeen, Moray, Shetland – are those with terminals for potential offshore geological storage infrastructure.
• There is a vast opportunity, particularly in Aberdeen, for repurposing depleted oil and gas fields as production tails off. This would extend the fields’ economic value and build on Scotland’s oil and gas expertise.
• With the construction of a national hydrogen pipeline infrastructure, connected hubs with a lack of geological storage may be able to pipe hydrogen to other storage facilities.
• Duisburg is advantaged by the fact that nearby hydrogen storage projects are under development (e.g. the RWE Gas Storage West project in Epe) (Hornby, 2023). These projects will be connected to Duisburg by the approved German core hydrogen network.

Pipeline network infrastructure

Scotland is actively pursuing several large-scale hydrogen pipeline projects to maximise the potential of our hydrogen and HDP sector (Scottish Government, 2024). Several key projects include the National Gas Project Union and an offshore pipeline from Scotland to Germany:

• National Gas Project Union will repurpose sections of the UK National Transmission System to carry 100% hydrogen (National Gas, 2025). These transmission pipelines will stretch from St Fergus in Aberdeenshire, down Scotland’s east coast and throughout the UK.
• The H2 Caledonia project plans to construct new hydrogen transmission pipeline to support the creation of Scotland’s hydrogen ecosystem (SGN, 2023). This project combines pre-FEED projects in Scotland’s Central Belt, Fife’s East coast and the Aberdeen Vision study.
• The Scottish Government is in Phase 2 of a project which is considering the development of an offshore pipeline from northeast Scotland to Germany. This would connect Scotland to the European Hydrogen Backbone pipelines (2024).

To score each hub’s potential pipeline infrastructure, we used the following scale from 1-6:

• There is no pipeline infrastructure suitable for hydrogen and no proposed or planned new hydrogen pipelines.
• There are existing gas pipelines which can be repurposed. There are no planned new hydrogen pipelines but there may be some projects proposed.
• There is a small-scale (e.g. distribution/spur pipelines) hydrogen pipeline project at any phase of development.
• There is a large-scale (e.g. trunkline pipelines) hydrogen pipeline project at any phase of development.
• The hub is a potential international export or import site for hydrogen and HDPs. However, the planned pipeline infrastructure is insufficient and/or the site is not well-established for international trade.
• The hub is a potential international export or import site for hydrogen and HDPs. There is sufficient planned pipeline infrastructure, and the site is well-established for international trade.

Figure 6: Hydrogen pipeline network infrastructure by hub.

Figure 6 shows the final hub scores for hydrogen pipeline infrastructure. As shown from left to right, Aberdeen is ranked highest, and the Argyll and Islands is ranked lowest.

We can take several key insights from our analysis and the hub rankings in Figure 6:

• In Scotland, Aberdeen, Cromarty, Orkney and Shetland are all hubs which could support export activity. They are all being considered as export locations for the Scotland to Germany pipeline project (Net Zero Technology Centre, 2023).
• Aberdeen and Duisburg rank highest with a score of 6/6.
• In the Aberdeen hub, St Fergus Gas Terminal is recognised as a well-established export route. St Fergus will be connected to the rest of the UK by the Project Union Hydrogen backbone pipeline project.
• With the largest inland container port in the world, Duisburg is planning to be a major import hub for hydrogen and HDPs (Gasunie, 2023). The approved 9,040 km German hydrogen core network should connect Duisburg sufficiently (Bundesnetzagentur, 2024).
• Hubs on the east coast of Scotland will benefit most from national and international trading opportunities. This is due to their relative proximity to mainland Europe and their planned connection to the Project Union and H2 Caledonia pipelines.

Ports

Access to ports is crucial for hydrogen hubs for several reasons:

• To engage in the trading and export of hydrogen (as a liquid, gas or LOHC) and HDPs by ship.
• To capitalise on the growing demand for HDPs to be used as shipping fuels, such as ammonia and e-methanol.

We have investigated which hubs are most suitable for meeting maritime shipping fuel demand and for trading hydrogen and HDPs by ship. To evaluate the scale of each hub’s maritime industry, we first scored the hubs based on the total freight traffic through their ports. This analysis was based on the Department for Transport’s Port Freight Statistics Publication (Maritime Statistics, 2024). We adjusted these initial scores based on several criteria, including:

• Does the hub have a port with existing or planned infrastructure for the storage, production or maritime fuelling of hydrogen/HDPs?
• Does the hub have a port with dimensions suitable for a typical small carrier vessel for transporting gas or ammonia? The Scottish Government defines these dimensions as a 100m length, 25m beam and a 12m draft (2020, p. 63).
• Does the hub have a port which is suitable for hydrogen/HDP exports to mainland Europe, as considered by the Scottish Government? Or, for Duisburg, is the hub a key port for hydrogen imports into Europe?

Figure 7: Port suitability for the hydrogen sector (higher score = more suitable).

Figure 7 shows the final hub scores and ranking for ports. As shown from left to right, Duisburg is ranked highest, and the Scottish Borders is ranked lowest. Several key insights can be made based on our analysis:

• Duisburg ranks highest with regards to port suitability for the hydrogen and HDP sector. As the largest inland container port in the world, Duisburg has by far the largest potential maritime fuel demand (Duisburger Hafen HG, 2025).
• Considering all of Scotland’s ports, Forth Ports in Grangemouth and Fife have the most freight traffic at around 19 million tonnes in 2023. Although, this figure only represents around half of Duisburg’s total freight traffic.
• The Scottish Government considers that the Aberdeen, Fife, Grangemouth, Shetland, Cromarty and Orkney hubs are most attractive for exports to Europe (2020). These hubs also have existing or planned port infrastructure for hydrogen.
• Without port redevelopment, most hubs do not have ports with suitable dimensions for the trade of ammonia by a typical carrier vessel. Those that do include Cromarty, Shetland, Aberdeen and Orkney.
• The Scottish Borders ranks lowest as it has no major or minor freight traffic in the region, and it scored negatively for all additional criteria.

Local policy and planning support

In Scotland, most industrial planning applications must be approved at the local council level. Local policy and planning support are crucial in sanctioning the construction of hydrogen hubs in Scotland. Streamlined planning processes and supportive local policy will help expedite the development of a robust infrastructure network. To investigate this capability group, we evaluated the industrial planning process duration and success rate for each hub. Hubs with shorter processing times and higher success rates for planning applications indicate that they are more supportive of industry and can support new infrastructure more efficiently.

Processing time for industrial planning applications

To assess hub processing time for industrial planning applications, we have taken an average of the relevant council areas. For Duisburg, the average processing time for construction permits in Germany is used (World Bank, 2024).

Figure 8: Average industrial planning process duration

Figure 8 shows the average number of weeks taken to process an industrial planning application in each hub. Ayrshire and Aberdeen are ranked highest with an average of 6.7 weeks of processing time, while Duisburg has an average 18-week processing time. Several insights can be taken from this analysis:

• Among the Scottish hubs, the range in average processing time is 10.9 weeks. The range of number of weeks taken is from 6.7 weeks to 18 weeks. This indicates disparity in local planning efficiency.
• On average, Scottish hubs process planning applications seven weeks faster than German industrial planning applications.

Success rate of industrial planning applications

To calculate the hub success rate for industrial planning applications, we have taken an average of the relevant council areas (Planning Application Statistics, 2024). No data was found for Duisburg, Argyll and Islands, Dumfries and Galloway, Moray, Orkney, Shetland or the Western Isles.

Figure 9: Hubs by average success rate of industrial planning applications.

Figure 9 shows the average success rate of industrial planning applications in each hub. The Scottish Borders is ranked highest with an average of 88%, while Ayrshire ranks lowest with an average of 50%.

When considering the average success rate and processing times for industrial planning applications together, Aberdeen is the most favourable hub for local planning and policy support. However, these two metrics do not always go hand-in-hand. While Ayrshire has the shortest processing duration for planning applications, these applications are also the least successful on average.

Co-location with innovation institutions

Innovation institutions with facilities for pilot-scale testing

Formed by Scottish Enterprise, the Scottish Hydrogen Innovation Network (SHINe) aims to support Scotland’s hydrogen and HDP sectors and accelerate innovation. SHINe innovation institutes can streamline access to the necessary infrastructure and expertise required to develop a successful hydrogen and HDP sectors. To assess this metric, we ranked the hubs by the number of SHINe institutions present. Innovation institutions include a range of projects like pilot-scale manufacturing capabilities of hydrogen related components, green hydrogen production, research centres, etc (Table 7). For Duisburg, we have assessed the number of comparable innovation institutions in the area (Scottish Enterprise, 2025).

Table 7: Innovation institutions and their capability for pilot-scale manufacturing by hub. Hub ranking is shown descending from the top (highest) to bottom (lowest) of the table.

From Table 7, we can take away several key insights:

• Aberdeen and Duisburg have the highest number of innovation institutions with pilot-scale manufacturing capabilities.
• SHINe innovation institutions are mostly concentrated in Scotland’s major cities – Aberdeen, Glasgow, Dundee and Edinburgh. One exception, with pilot-scale manufacturing capabilities, is the European Marine Energy Centre in Orkney.
• The majority of hubs have no local SHINe innovation institutions.

Financial aspects

While not included in the scope of this project, we recognise that financial aspects can impact hydrogen hub supply chain development. According to the UK Government, the UK’s industrial electricity prices were 25.85 pence per kWh in 2023 including taxes (Energy Prices Statistics Team, 2024). This price is 70% higher than the average of the EU and G7 countries. As electricity costs account for some 70% of the total cost of green hydrogen, these high prices could hamper grid-connected project economics (Renewable UK & Hydrogen UK, 2025). Regional hubs with higher electricity prices could be impacted more. Notably, North Scotland has some of the highest electricity distribution costs in the UK (Gallizzi, 2025). Additionally, rural hubs may experience greater transportation costs to procure goods, services, and labour. For island-based hubs, reliance on a rotational workforce from the mainland could further impact their competitiveness by driving up labour costs.

Overall supply chain capabilities

To assess overall supply chain capabilities, we have calculated a total score for each hub from the metrics discussed above. Each metric has been assigned a specific weight, based on their importance to producing HDPs and the confidence in the quality of available data. Table 8 shows the final weightings we applied to each metric. For each hub, we scaled each metric by the relevant weighting. We then summed the resulting metric scores to give a final score out of 100. The overall hub ranking for supply chain capability is shown in Figure 10.

It is important to note that the purpose of this analysis is not to find the absolute “best” hydrogen hub in Scotland. By ranking the hubs in each metric, we have assessed their relative strengths and weaknesses. This detailed analysis provides the nuance required to understand each hub’s overall supply chain capabilities. The metric weightings selected provide an expert-based view on the supply chain capabilities of each hub. However, as shown by sensitivity analysis (detailed in Appendix B), hub rankings can vary when metric weightings are altered. The conclusions drawn from the final hub scores detailed below should be viewed in this context.

Table 8: Metric weightings for final hub scoring.

Figure 10: Final scores for hub supply chain capability.

From Figure 10, our analysis suggests that the Aberdeen hub has the greatest relative supply chain capability (90/100), while Argyll and Islands has the lowest (27/100). There are several conclusions that we can take from these final scores:

• Aberdeen stands out as being particularly capable to support the hydrogen and HDP sector. The hub ranked highest for 7 metrics out of 11, including:
• Maximum renewable power generation
• GVA of the energy industry
• Full-time equivalent workers in energy and engineering
• Large-scale storage capacity
• Pipeline network infrastructure
• Processing time for industrial planning applications
• Innovation institutions with facilities for pilot-scale testing
• Cromarty and Glasgow are also identified as attractive hubs.
• The Cromarty hub benefits from excellent access to offshore wind developments, a strong current workforce and major port infrastructure at Cromarty Firth with identified export opportunities.
• The Glasgow hub benefits from a particularly strong workforce capability and plentiful access to effluent water as well as support from innovation institutions and major port infrastructure from the Clydeport network.
• While specific strengths vary between hubs, the majority of Scotland’s hydrogen hubs can be broadly grouped by overall supply chain capability.
• Cromarty, Glasgow, Fife, Grangemouth and Ayrshire fall into an “upper category” with scores ranging only three points (58-61).
• Dundee, Moray, Dumfries and Galloway, Shetland Orkney and the Scottish Borders broadly fall into the “lower category” with scores ranging from 40-47.
• The Aberdeen hydrogen hub offers a promising opportunity to compete with local Duisburg supply in the Ruhr region. However, considering their similarly high scores, any of the Scottish hubs in the “upper category” may also be considered to be well placed. As the Ruhr area aims to be a model hydrogen region, this result indicates Scotland’s potential competitiveness in the European market.
• On the other hand, Western Isles and Argyll & Islands have promising renewable power generation potential. Development of green hydrogen production may therefore help address grid curtailment issues and address local, isolated demand. However, their supply chain capabilities are hindered by a lower workforce capability and fewer connections to suitable ports, large-scale storage and pipelines.

Overall, Scotland’s hydrogen hubs are relatively well balanced in their supply chain capabilities and have the potential to contribute significantly to both the national and international hydrogen market. The Aberdeen and Cromarty hubs particularly excel, while the Western Isles and Argyll and Islands may face resource limitations. By enhancing the strengths of higher-scoring hubs while addressing others’ limitations, Scotland will ultimately improve its competitive position in the global market.

HDP demand in Scotland’s hydrogen hubs

The Scottish Government’s Hydrogen Action Plan identifies that low-cost green hydrogen production is key to the net-zero transition (2022). To minimise the additional cost of transportation and other supporting infrastructure, the Scottish Government plans to encourage the “aggregation of cross-sectoral demand and co-location of the whole hydrogen value chain”. Thus, the efficiency of co-locating supply with high local demand will support the rapid scaling of Scotland’s hydrogen and HDP sectors. This rationale underpins the hydrogen hub model.

In this chapter, we analyse and estimate the addressable market or demand for each HDP in each hub. This analysis will initially provide a view on which hubs are most suited to supporting the development of local HDP demand in Scotland (Section 4.1.5). In Chapter 5, we bring together our supply chain capability and demand analysis to identify co-location opportunities for HDPs.

We assess the hubs based on current demand opportunities, which will initially support rapid market scaling. Therefore, we define HDP demand as the addressable market that HDPs could supply in a complete fuel-switching scenario. This enables us to differentiate hubs and provide a relative view on HDP demand opportunities. We assess four key sectors which could support the aggregation of cross-sectoral HDP demand within Scotland’s hydrogen hubs:

• Ammonia and e-methanol fuel for the maritime sector.
• Ammonia-based fertilisers for the agriculture sector.
• E-methanol feedstock for the chemical sector.
• SAF for the aviation sector.

To differentiate HDP demand by end use, our analysis considers HDPs used for direct consumption, excluding HDPs used as a hydrogen carrier (e.g. LOHCs).

Please refer to Appendix C for further information on this section’s methodology, sources and raw data.

HDP fuel for maritime shipping

In 2021, UK shipping used over seven million tonnes of fossil marine fuel oils, accounting for 18% of UK transport emissions (Transport & Environment, 2023). As the global regulatory body for shipping, the International Maritime Organisation (IMO) has set a 2050 net zero target for international shipping (IMO, 2023). In conjunction with Scotland’s net zero target, this means that the Scottish maritime industry will seek to replace fossil-based shipping fuels. The UK shipping industry can be decarbonised with HDPs, such as ammonia and e-methanol.

To evaluate the addressable market for these HDPs, we have analysed the current shipping fuel demand for each hub. There are uncertainties on which HDP shipping fuel – ammonia or e-methanol – will predominately address the market. Therefore, we have based our calculation on total energy demand in TWh.

Based on the UK’s 2021 marine fuel consumption, we calculated the annual energy demand for shipping. We then assigned this demand proportionally to each hub according to its total shipping traffic (Maritime Statistics, 2024).

Figure 11: Ranking of hubs by HDP shipping fuel demand.

Figure 11 shows the addressable market for HDP shipping fuel in each hub. Fife and Grangemouth rank highest with 3.5 TWh of demand, while the Scottish Borders ranks lowest with no current demand. From Figure 11 and our analysis, there are several key insights to address:

• Forth ports in Fife and Grangemouth is likely to be the largest addressable market for HDP maritime fuels, followed by the Clydeport network in Glasgow and Ayrshire.
• Forth ports and the Inverness and Cromarty Firth port network are Green Freeports (Inverness & Cromarty Firth Green Freeport, 2025; Forth Ports, 2025). These ports have varied tax and custom rules which could incentivise the development of HDPs for maritime fuel.
• While we have covered shipping demand, there may be other smaller sources of maritime demand for HDP fuels that were out of scope for this project. These sources include fishing vessels, ferries, service vessels and tugs.

Ammonia-based fertilisers for agriculture

The International Energy Agency estimates that around 70% of ammonia produced is used to make nitrogen-based fertilisers (2021). Ammonia production, by the Haber-Bosch process, is fossil-fuel based and highly energy intensive. The process accounts for 2% of the world’s total final energy consumption and 1.3% of carbon dioxide emissions from the energy system (International Energy Agency, 2021). As a sustainable alternative, green ammonia is gaining attention to decarbonise fertiliser production.

We have estimated green ammonia’s addressable market for fertilisers in each hub. First, we estimated total nitrogen-based fertiliser demand in Scotland for cropland and grassland. For this, we used average fertiliser application rates from UK Government data (UK Government, 2023). We also assumed that the nitrogen-based fertilisers were urea and ammonium nitrate, applied in equal proportions. From this assumption, we estimated the ammonia required to produce these fertilisers. Finally, we allocated this ammonia demand across the hubs based on their share of agricultural GVA in Scotland.

It is important to note here that we have only considered nitrogen-based fertiliser in our analysis, and not any other type of fertilisers. Therefore, our demand analysis only represents a subset of demand for fertilisers and not the total demand for fertilisers in Scotland.

Figure 12: Ranking of hubs by demand for green ammonia fertilisers. The ranking is shown from left (highest rank) to right (lowest rank).

Figure 12 shows green ammonia’s addressable market for fertilisers in each hub. Aberdeen ranks highest with 0.14 TWh of demand – around 31% of Scotland’s total demand. Moray and the island hubs rank lowest. Green ammonia’s addressable market will likely be greater on Scotland’s east coast where there is more agriculture.

E-methanol feedstock for chemical production

The International Renewable Energy Agency (IRENA) estimates that around 98 million tonnes of methanol is produced globally each year (IRENA and Methanol Institute, 2021). It is mostly used as a feedstock – a starting material – to produce formaldehyde, acetic acid and plastics. Currently, we produce most methanol from fossil fuels – such as synthetic gas (syngas). Methanol emissions represent around 10% of the chemical sector’s carbon dioxide emissions, and addressing these will be key for decarbonising the sector. E-methanol, produced with green hydrogen and captured carbon dioxide, could address methanol’s current market.

In Scotland, we assume that Grangemouth Chemical Science Park is the only large-scale user of methanol as a chemical feedstock. It is one of only four major chemical parks in the UK, and the only one in Scotland (Scottish Development International, 2023). With the closure of the refinery, Grangemouth’s industrial future is uncertain. However, INEOS’s Olefins and Polymers business will continue running as usual (INEOS, 2024). Their two onsite ethane cracker plants have the capacity to produce 1 million tonnes of ethylene per year (Endeavor Business Media, 2016). Fossil-based hydrogen and methane are produced as a by-product from an ethane cracker and can be used as syngas (Brooks, 2013).

To evaluate the maximum potential addressable market, we assume that this syngas is used to produce methanol. From this, we estimate that e-methanol could address a maximum demand of 100,000 tonnes per year (0.56 TWh).

SAF for aviation

The UK SAF mandate determines the share of SAF in total UK jet fuel demand (UK Government, 2024). It sets key SAF targets of 2% by 2025, 10% by 2030 and 22% by 2040. In securing demand, this mandate incentivises SAF production and supply across the UK.

To evaluate the addressable market for SAF, we analysed the current aviation fuel demand for each hub. To achieve this, we assigned the UK’s aviation fuel consumption in 2022 proportionally to each hub according to its total aircraft movement. To capture Edinburgh airport’s fuel demand, we have assigned it to the nearby Grangemouth hub.

Figure 13: Ranking of hubs by aviation fuel demand.

Figure 13 shows the addressable market for SAF in each hub. The airports in each island hub are shown combined: Shetland includes Lerwick (Tingwall), Scatsta and Sumburgh; Orkney includes Kirkwall and Wick John O’Groats; Western Isles includes Barra, Benbecula and Stornoway; Argyll and Bute includes Cambeltown, Islay and Tiree.

Grangemouth ranks highest with 5 TWh of demand, while hubs with no airports rank lowest. Regionally, about a third of SAF demand would arise from Edinburgh Airport and around a quarter from Glasgow Airport and Glasgow Prestwick. From Figure 13, we can see that locating SAF production around Scotland’s major airports would maximise co-location synergies. Progress has already begun in this area:

• In 2021, Edinburgh Airport signed a Memorandum of Understanding with Ørsted (Edinburgh Airport, 2021). The partnership recognises the importance of HDPs to accelerate the shift to sustainable air travel.
• In 2022, AGS Airports which own and operate Aberdeen and Glasgow airports, signed an agreement with ZeroAvia (Glasgow Airport, 2022). This partnership is exploring the development of hydrogen fuel infrastructure for zero-emission flights.
• In 2024, the Glasgow Airport Hydrogen Innovation Hub consortium delivered a feasibility study for a hydrogen hub at the airport (Glasgow Airport, 2024).

Overall HDP demand opportunities

The maritime and aviation sectors will be the main sources of HDP demand as Scotland scales its hydrogen and HDP sectors. These sectors account for 97% of the roughly 35 TWh addressable market analysed in this report. Due to this scale, our analysis suggests that hubs with major ports and airports would be best suited to develop HDP demand opportunities. In this regard, the hubs that stand out are Grangemouth (with 9.1 TWh of demand opportunity), Glasgow (with 6.1 TWh) and Aberdeen (with 4.4 TWh). Grangemouth’s advantage arises from several factors:

• An established and experienced chemical industry.
• Developed port infrastructure within the major Forth Ports network.
• Proximity to major airports, like Edinburgh Airport.

The Scottish Borders notably have the lowest demand opportunity overall. It is disadvantaged by the lack of shipping, aircraft traffic and chemical industry as well as a relatively small agricultural sector.

The potential demand opportunity for HDPs is greatest for SAF with a total addressable market of approximately 18 TWh. In comparison, e-methanol and green ammonia have a combined total of around 17 TWh.

Overall, our demand analysis has identified that focus should be placed on developing major offtake opportunities from the maritime and aviation sectors. This focus would best facilitate the large-scale and rapid scaling of the Scotland’s domestic HDP market. As the Scottish Government identified in the Hydrogen Action Plan, aggregating multiple end-use applications for production streams would improve the economic benefit of Scotland’s hydrogen hubs. Therefore, while SAF does have the greatest demand opportunity, it is worth noting that green ammonia and e-methanol have more diverse end uses and so would be better suited for demand aggregation. As such, each HDP has a distinct potential role in accelerating Scotland’s hydrogen and HDP sectors.

Co-location of HDP supply chain capabilities and demand opportunities

The Scottish Government recognises that co-location of supply and demand will help develop a sustainable domestic hydrogen and HDP sectors (2022). This development is required to establish Scotland in the wider global market (2022). In this chapter, we bring together our insights from the supply chain capabilities in Chapter 0 and the demand analysis in Chapter 4. This enables us to identify co-location opportunities for HDPs within Scotland’s hydrogen hubs.

Figure 14 summarises the co-location opportunity in each hub. The x-axis shows the overall supply chain capability score; the y-axis and bubble size show the aggregated demand opportunity. The top right quadrant broadly indicates which hubs may be best suited for co-location.

Figure 14: Overall co-location analysis showing the relative supply chain capability on the x-axis and the demand opportunity on the y-axis and as the relative bubble size.

From Figure 14, it is interesting to note that the top hydrogen hub for supply chain capability is not the one with the greatest demand opportunity. Aberdeen has the greatest supply chain capability score (93/100) while, with Edinburgh Airport and Forth Ports, Grangemouth has the greatest HDP demand opportunity (9.1 TWh). This supports the idea that these analyses should not be looked at in isolation. Rather, differing hub strengths can favour the development of different sections of the HDP economy.

Looking at the top right quadrant, we note that Aberdeen, Glasgow and Grangemouth are most aligned to facilitate the development of a regional, co-located HDP economy. In general, the hubs identified as strongest in supply chain capability – including Grangemouth, Aberdeen, Glasgow, Fife and Cromarty – are also those with greater demand opportunity.

We identify the Western Isles and Argyll and Islands as hubs which may need further support to develop their supply chain capabilities. On the other hand, the Scottish Borders and Moray may need to identify other, smaller offtake sectors to capitalise on co-location efficiencies.

The balancing of supply and demand opportunities will require careful consideration, particularly in the early stages of Scotland’s hydrogen and HDP sector development. Favouring supply opportunities could increase the cost and logistical complexity of transportation and storage to address more distant demand. Conversely, locating supply based on demand opportunities could limit the capacity and the economics of supply.

Overall, the diversity of Scotland’s hydrogen hub strengths points to the importance of a cross-hub approach, in addition to co-locating demand with supply. Hubs with greater connectivity to pipeline and port infrastructure, such as Aberdeen, will be more able to take advantage of this approach. As suitable pipeline and port infrastructure develops, supply and demand opportunities will be unlocked that are not possible by co-location. For example, piped green hydrogen from Fife could support HDP production in the adjacent Grangemouth hubs. For hubs with lower connectivity, such as the Western Isles, further development of suitable infrastructure is required to access cross-hub opportunities. Overall, the growth of HDP production will require both cross-hub and co-located approaches. Balancing these will help maximise each hub’s potential and, ultimately, that of the hydrogen sector itself.

Regulatory considerations for the HDP sector

Each HDP has different health, safety and planning requirements due to differing chemical properties. These requirements are stipulated by UK regulations. Higher hazard HDPs may face more severe limitations in how, where, and in what quantities they can be handled, for example for production or storage. This section explores the UK regulatory environment and its potential impact on the development of the HDP economy in Scotland.

Hazards associated with HDPs

Table 9 shows the physical, health and environmental hazards of hydrogen and HDPs. These hazards were identified from the standardised safety data sheet for each substance. The LOHC that we analysed was methylcyclohexane (MCH), the most common LOHC. The rating from 1-4 indicates the highest hazard severity category for each hazard type. According to the Globally Harmonised System classifications, a Category 1 hazard is the most severe while a Category 4 hazard is the least severe (United Nations, 2019).

Table 9: Hazards of hydrogen and HDPs from 1 (most severe) to 4 (least severe).

From Table 9, we can see that ammonia is the most hazardous substance overall. Handlers must monitor it closely to mitigate its Category 1 health hazard and environmental hazards. LOHCs, E-methanol and SAF are less hazardous overall, although all also have Category 1 health hazards. This means that handling these HDPs is generally less inhibitive than for ammonia. As a feedstock, hydrogen’s severe flammability and explosion hazards should also be considered carefully for any HDP production development.

Review of key UK regulations affecting HDP handling

Due to these physical, health and environmental hazards, HDP production is strictly controlled by UK regulations and regulatory authorities. With the exception of LOHCs, HDPs like ammonia, methanol and aviation fuel are already produced and handled on a large-scale globally. Therefore, there are relatively few new regulatory issues concerning these HDPs. We have reviewed several key regulations that site handling HDPs must adhere to. These are detailed in Table 10.

Table 10: Key regulations and regulatory bodies and their implications for HDP production.

It is important to note that, under COMAH, each HDP is subject to different regulatory requirements based on their hazards, classified by the Globally Harmonized System (GHS). Based on the COMAH Lower Tier threshold quantity for each HDP, we have broadly ranked the HDPs by the regulatory stringency required to manage its hazards.

Table 11: Rank of HDPs by their COMAH Lower Tier threshold. The associated energy content of LOHC assumes the theoretical hydrogen storage content of MCH (6.22 wt%). Energy content of the HDPs was sourced from (Ozkan, et al., 2024).

From Table 11, we can see that LOHC and ammonia are the most stringently regulated by COMAH with the same Lower Tier threshold of 50 tonnes. However, as an energy carrier of hydrogen, LOHC handling is more limited by the threshold. The associated energy content of LOHC is 0.5×10¹² J lower than that of ammonia. In comparison, e-methanol and SAF are less stringently regulated by COMAH. By energy content, a Lower Tier COMAH site would be able to handle 25x more e-methanol or over 250x more SAF than LOHC. Therefore, based on the stringency of COMAH regulations, the simplest HDP to handle is SAF, followed by e-methanol, ammonia and LOHC.

Hub-level regulatory capabilities

Considering the hazards associated with hydrogen and HDPs, hubs with more regulatory experience are likely to be better suited to handling these substances safely. For HDP production, existing COMAH sites may be expanded or new COMAH sites developed. As a broad measure of current and relative regulatory experience at a hub level, we will evaluate the number and tier level of COMAH sites present in each hub. The presence of COMAH sites, with their existing infrastructure and workforce, indicates that a hub may be more capable at handling hazardous HDPs safely according to regulation. Identifying these sites can also provide insights into potential offtakers as well as production, storage and distribution sites for HDPs.

Figure 15: Number of Upper Tier COMAH sites present in each hub.

We have assessed the number of registered COMAH sites in each hub as of June 2023 (Health and Safety Executive, 2023). There are two tiers of COMAH site: a Lower Tier and an Upper Tier. Upper Tier sites are more stringently regulated since they handle greater quantities of hazardous substances. Figure 15 shows the number of Upper Tier COMAH sites in each hub. Grangemouth has the most (16), including the Grangemouth Terminal and INEOS chemical sites. This indicates that the Grangemouth hub, and its associated workforce, may have the most regulatory experience for the large-scale handling of hazardous chemicals. The terminal, for instance, already facilitates the supply of Scotland’s aviation fuel (Forth Ports , 2025).

Key COMAH Upper Tier sites include:

• The St. Fergus Gas Terminal in the Aberdeen hub. This site receives, processes and compresses North Sea gas for the National Transmission System as well as stores and distributes other chemicals and fuels (North Sea Midstream Partners, 2025).
• The Clydebank Terminal operated by Exolum in the Glasgow hub. This site has a storage capacity of 56,257 m³ and a jetty to receive and storage liquid products, including fuels (Exolum, 2025).
• Moray’s sites are predominately distilleries which are engaged offtakers for the hydrogen sector. In March 2025, Storegga submitted a planning application to Moray Council to construct a 25 tonne per day green hydrogen facility to decarbonise local distilleries (Storegga, 2025). The UK Government has also found LOHCs to be a viable option for supplying hydrogen to distilleries, and could be explored further for the decarbonisation of Scotland’s distilleries (BEIS, 2021).

These hubs are likely to have a lower safety risk for handling HDPs. This is due to their existing regulatory experience and infrastructure. These insights are supported by the fact that the number of COMAH sites in each hub generally aligns with its overall supply chain capability score: the “upper” and “lower” hub groupings are broadly preserved. In comparison, the Scottish Borders has only one Lower Tier COMAH site, a fuel storage and distribution site operated by Flogas Britain. This relatively limited experience could indicate that there is greater need for local workforce training, community engagement and risk communication and investment into infrastructure to support the safe development of a local HDP sector.

Overall, this broad hub-level analysis has provided an indication of hubs’ regulatory capabilities. While out of scope for this project, individual assessment of existing and potential COMAH sites would add value to the analysis. This would provide greater detail into the specific capabilities of each hub to handle, produce and distribute HDPs safely, in accordance with regulations.

Policy gap analysis

In the previous chapters, we identified the strengths and barriers for Scotland to scale up its HDP market. To maximise opportunities a favourable and clear policy landscape is needed. This landscape must consider policy at a devolved, national and regional level. This will ensure that Scotland’s HDP related policies work with UK and EU specific policies in a harmonious manner.

To that end, we analysed relevant policies in the UK, Scotland or the EU. We considered policies in the following categories:

• Subsidies and obligations
• Supply chain/infrastructure development
• Technical and safety regulations
• Licensing
• Planning and consenting

Scottish policy gaps

Here we describe the main policy gaps, and the resultant risks, faced by the Scottish HDP industry. The Scottish Government has already taken some positive steps. However, plugging some gaps will significantly improve the standing of the industry.

Supply chain incentives/development for HDPs

The Scottish Government recently published plans to realise export opportunities for green hydrogen (International Trade and Investment Directorate, 2024). Although this a very important step in furthering the interest of Scottish exports to nearby regions, there are still some gaps remaining. The government’s plan identifies the various investment opportunities and barriers. However, there is a need for more clarity on how the Scottish Government will collaborate with the UK Government or build relationships with international export partners. Timely publication of such plans will provide investors with more certainty.

Clarity in planning and consenting

The Scottish Government has made substantial progress in improving the planning regime for hydrogen projects. The government is committed to preparing and training its planning authorities to expedite hydrogen planning applications. Additionally, it also aims to provide planning authorities with access to specialist expertise and staff upskilling. The government aims to do this this by introducing the planning hub. As a first step towards achieving their goal of improving the planning regime, the Scottish government conducted stakeholder engagement (Improvement Service, 2025), which attempted to understand concerns of both the planning authorities and industry.

The Improvement Services report focussed on five areas: understanding of hydrogen within planning applications, regulatory regime, more clarity on planning process, impact and risk of hydrogen manufacturing, and spatial factors. Some of the key concerns raised by the planning authorities were about lack of clarity on roles when multiple bodies are involved in a planning/consenting process. Additionally, resource constraints faced by the authorities and lack of awareness about hydrogen applications are some of the other concerns raised. For industry, some of the major points raised concerned uncertainty regarding water availability and Hydrogen Allocation Round (HAR) timelines. Industry also proposed conducting wider public engagement to spread awareness about how hydrogen can safely play a role in Scotland’s net zero transition.

All this effort has been crucial in shining some light on the challenges faced by industries and policymakers. To fully capitalise on this initiative, the government should now focus on implementing the findings and recommendations from their engagement.

UK policy gaps

The UK government has implemented many policies that have boosted green hydrogen development in the national economy. Our analysis concludes that the success of such policies should be replicated to similarly develop the HDP space.

Lack of HDP considering in subsidies and obligations

The Hydrogen Storage Business Model (HSBM) does not currently include HDPs in its scope.

There are a number of benefits to including HDPs in HSBM. It would increase the avenues available for storing hydrogen. It would also allow for small scale storage of hydrogen in the form of hydrogen derivatives (HSBM currently focusses on large-scale hydrogen storage). Additionally, inclusion of HDPs in scope may mitigate some of the challenges associated with storing hydrogen, such as safety concerns. For example, as ammonia contains hydrogen, including it in HSBM could act as an alternative way of storing hydrogen.

Supply chain incentives for industry and innovation

We identified a policy gap in relation to encouraging links between industrial clusters, which are well suited to producing HDPs. Chapter 4 showed how there are multiple hubs which are optimal for producing HDPs. Collaboration between the different clusters in these hubs would allow for sharing knowledge and potentially products as well.

There also needs to be a focus on conducting trial and demonstration projects. Many hydrogen projects will use innovative technology which will need to be proven and demonstrated in real-life settings. Trials will go a long way in assessing whether investing in such technologies is worthwhile.

Updating technical and safety regulations

Regulations regarding hydrogen need to be updated in the UK. Onshore hydrogen projects are regulated under the Gas Act 1986 and Planning Act 2008, and hydrogen is generally referred to as a ‘gas’. The Gas Safety Management Regulation (GSMR) prohibits injecting more than 0.1% of hydrogen into gas networks. Although there are discussions ongoing to exempt hydrogen from this rule, there needs to be more clarity here (Pinsent Masons, 2023). Repurposing the gas network to enable hydrogen transport is essential to grow the HDP sector. Green hydrogen is an important input for HDPs. Hence, a developed transport system will remove supply bottlenecks for HDP producers.

Clarity in offshore licensing

The industry seeks more clarity on the timeline and details of future offshore hydrogen regime. These projects will be critical in developing HDP production.

Delays in planning and consenting

Green hydrogen and HDP projects require various regulatory approvals, environmental permits, etc. Many investments are subject to approval of such plans. Delays associated with the planning and consenting regime may extend the lead time of green hydrogen projects. Streamlining the regime will mitigate some of these issues.

International policy gaps

Lack of clarity on emissions factors

There is an urgent need to standardise the emission factors for many fuels, such as ammonia or methanol. Sectors that use such fuels will need a standard emission factor as it eases carbon accounting and adhering to different regulations.

Lack of a standard framework for low-carbon hydrogen

There is a misalignment between low-carbon hydrogen standards in different countries. To foster international trade, a uniform definition of low-carbon hydrogen is needed.

Recommendations

Chapter 7 outlines relevant current policies that can enable development of the hydrogen and HDP sectors in Scotland. While introducing such policies is a significant step towards building the hydrogen space in the UK, some gaps remain. In addition, there is policy action required at an international level. Addressing these issues will significantly improve the prospects of Scotland’s hydrogen and HDP sectors.

A summary of our recommendations is as follows:

• The Hydrogen Sector Export Plan showcases the Scottish Government’s commitment to building hydrogen export capabilities. However, there is a need for more information on how the Scottish and the UK governments will work together with potential trade partners.
• Scottish Government should continue the progress on building a hydrogen planning regime. This will build on the introduction of the planning hub and the subsequent stakeholder engagement. This momentum should be continued by addressing the main findings of the Improvement Services report.
• The UK Government should include HDPs in the scope of subsidies like HSBM. HDP projects face similar risks as hydrogen projects. Therefore, providing similar subsidies to HDPs projects will mitigate risks and provide more certainty.
• Due to many hydrogen projects using innovative technology, there is a need for increasing the number of trials and demonstration projects.
• Another important issue is the potential misalignment of many standards and definitions. For instance, different governments should collaborate and decide on a common definition for low-carbon hydrogen. These misalignments will hinder growth opportunities as they increase the risk for potential traders.

There needs to be a more detailed plan for prioritising hub development. Our analysis highlighted the strengths and weaknesses of each hub. These results should be used to organise collaboration between production and demand hubs. Additionally, as shown in the co-location analysis, the ideal production hubs aren’t necessarily the same as the key demand hubs. Sorting this misalignment might require government intervention and support.

Conclusions

In our examination of Scotland’s industrial capabilities to produce hydrogen derivatives and products, we looked at supply chain capabilities, demand opportunities, regulatory and policy analysis.

Our assessment of co-location of supply chain capabilities with demand suggests Aberdeen and Grangemouth stand out as key hubs for the development of HDP production. Additionally, Cromarty and Ayrshire offer strong supply chain capabilities and Glasgow and Fife present significant demand opportunities. Meanwhile, the Western Isles and Argyll and Islands may require targeted support to enhance their supply chain capabilities. The Scottish Borders may need support in developing greater regulatory experience to facilitate HDP development.

Many of the Scottish hubs scored highly on the metric of renewable power generation capacity. This is evidence of Scotland’s biggest strength: access to renewable energy. Regions like Aberdeen, Cromarty, Moray, Shetland and Western Isles were the highest scores. Regarding local policy and planning support, Aberdeen, Ayrshire and Scottish Borders were among the top performers.

Given the nascency of HDP production, a favourable policy environment is needed to ensure rapid adoption of these fuels. In Scotland a more nuanced planning regime would help to support the growth of HDP adoption. Scotland would benefit from a planning regime that accounts for its specific geographic factors.

At the UK level, HDPs should be included in the scope of policies like HSBM. Health and safety regulations should be updated to account for the increasing role of hydrogen and HDPs in the economy of the future.

Our analysis shows that for Scotland to meet its aims of becoming a major exporter of HDPs, it will need a holistic approach to evaluating the strengths of Scotland’s potential hydrogen hubs.

Overall, by balancing cross-hub collaboration with localised development, Scotland can maximise the potential of HDP production from green hydrogen, driving the sector’s long-term growth and resilience.

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Appendices

1. Current state of play

To understand the role that Scotland can play in the hydrogen and HDP sectors of the future, a thorough review of literature was undertaken. The current state of the hydrogen and HDP sectors in Scotland will very much dictate its future prospects. For the purposes of this study, the literature review focussed on many factors associated with the production and export of hydrogen by Scotland. The review allowed us to identify certain common themes related to Scotland’s ambition for net zero and revealed hydrogen’s role in achieving those goals.

We explored the potential key drivers and enablers of the hydrogen and HDP sectors. Then, we analysed barriers Scotland is likely to face in growing its hydrogen supply chain capabilities. Apart from studying strengths and weaknesses specific to Scotland, we also analysed factors specifically relevant to the HDPs in scope of our study.

Scotland specific factors

Most of the literature reviewed concludes that Scotland is very well-placed to be able to produce green hydrogen in the future. There are many factors that work in Scotland’s favour. First and foremost, Scotland’s access to abundant levels of renewable energy, especially offshore wind, is a major strength (ClimateXChange, 2023). Production of green hydrogen will require renewable electricity as the major component. Scotland’s wind resources make it very suitable for producing green hydrogen.

Another major key driver for Scotland’s hydrogen and HDP sectors is the ambitious policies in the EU. These policies are likely to spur hydrogen demand in the next few decades. According to the RePowerEU Strategy, the EU aims to import 10 million tonnes of hydrogen by the year 2030. This provides Scotland with a significant opportunity to be a major exporter of low-carbon hydrogen to the EU (Scottish Government, 2022). Since the Russia-Ukraine conflict, the EU also aims to stop importing natural gas and rely on its domestic capabilities (Scottish Power, 2022). This will also likely further the usage and demand for hydrogen in the continent.

Scotland is also likely to benefit significantly from its geographical proximity to the EU. Hence, Scotland may transport hydrogen and HDPs to the EU at costs lower than faraway regions like North America, the Middle East or Asia (ClimateXChange, 2023).

In addition, there are other factors working in Scotland’s favour. For example, Scotland has a vast oil and gas industry with a highly skilled workforce. These skills can be transferred to the hydrogen and HDP sectors (Scottish Enterprise, 2024).

On the other hand, the literature reviewed also highlighted areas which need further development and focus to enable green hydrogen production. One of the biggest weaknesses identified in the literature is the high costs associated with electricity generation. Electricity cost is one of the biggest components of green hydrogen production. Currently, cost of electricity generation is much higher in Scotland compared to other competitor regions like the USA or the Middle East (ClimateXChange, 2023). This makes green hydrogen production in Scotland more expensive than regions like the US or the Middle East. This could reduce Scotland’s competitive edge to export to the EU.

Past studies also point out the lack of electrolyser manufacturing capabilities in Scotland as a potential bottleneck (ClimateXChange, 2024). Another major challenge faced by Scotland is regarding transporting and storing hydrogen or HDPs (Optimat and Scottish Enterprise, 2023). Scotland lacks a dedicated pipeline infrastructure that could be used to transport hydrogen to the EU. However, many studies point out the possibility to repurpose existing gas pipelines and use them for hydrogen transport. Scotland also lacks onshore deposits for salt caverns. However, this can be mitigated by the existence of depleted gas fields and lined rock caverns (ClimateXChange, 2024).

Some of the studies also mention the lack of projected demand for hydrogen in Scotland as a potential issue. Scotland is not expected to demand very high levels of hydrogen, meaning hydrogen supply capabilities will be built to service external demand. Increasing demand will be contingent on the policies that will be enacted in the future.

Similarly, studies have pointed out the need for more clarity from the government on possible policy actions (Scottish Enterprise and Optimat, 2023). The sector will also benefit from a coordinated response to tackle supply chain issues and more visibility into existing opportunities. Databases similar to the Offshore Energy UK’s Supply Chain Visibility Tool and the North Sea Transition Authority’s (NSTA) Energy Pathfinder will increase awareness and information regarding opportunities and enable potential investors to make informed decisions (Aberdeen City Council, n.d.).

The lack of clarity and uncertainty regarding future policy making explain why hydrogen demand projections by different studies vary significantly. Latest demand projections for Scotland for hydrogen expect demand to be in the range of 0.6-2.7 TWh for 2030 and 2.7-24.7 TWh for 2050 (Morton, et al., 2025). Some studies project the economic impact of exporting hydrogen products to the EU. According to the ambitious scenario of the Hydrogen Action Plan, 2022 report, exporting hydrogen to the EU could create roughly a total of 300,000 jobs in Scotland by 2045. It could also add roughly £25 billion every year to the Scottish economy by 2045 (Scottish Government, 2022).

The findings from these studies show that Scotland has inherent strengths that can be harnessed to build and grow strong hydrogen and HDP sectors. Scotland’s access to renewable energy and the skills possessed by existing workforce puts it in a very robust position. However, building supply chain capabilities in Scotland will also come with its own challenges. The biggest challenge faced by Scotland is the high cost of generating renewable electricity. Lack of storage and transport infrastructure is also a big issue. Many studies have pointed out the need for government support to mitigate such challenges.

HDPs specific literature review

The literature review conducted also focussed specifically on the current state of HDPs production in Scotland and the UK. In some cases, it makes more economic sense to use a hydrogen product than hydrogen itself to achieve decarbonisation. This is specifically true for two hard-to-abate sectors: aviation and shipping. Two of the most mentioned hydrogen products in our literature review were sustainable aviation fuels (SAFs) and ammonia.

SAFs are expected to play a major role in decarbonising aviation. Currently, very little SAF is supplied to Scottish airports. Nevertheless, in the long-term, SAFs will be key to replacing high-carbon jet fuels. According to the SAF Mandate, roughly 2% of the UK’s jet fuel demand in 2025 will be from SAFs. The share of SAFs in final jet fuel demand will increase to 10% by 2030 and to 22% by 2040. The global SAF demand is expected to reach 22.7-32.8 million tonnes by 2030 (Scottish Enterprise and Optimat, 2023).

In addition to SAFs, using hydrogen directly as a fuel is also a solution that can be deployed to decarbonise aviation. Direct use of hydrogen in aviation is not expected to be used as much as SAFs (Scottish Enterprise and Optimat, 2023). This is partly because of hydrogen not being a drop-in fuel, whereas SAFs are. Drop-in fuels are fuels that can be used in an airplane without making any modifications to the engine. This increases cost for air carriers to use it as an alternative to high-carbon fuels currently used. Another major concern is the safety issues that using hydrogen will pose. In addition, due to hydrogen being a lighter fuel, its volumetric density is lower. This means that a lot more hydrogen will be required to operate an airplane, increasing storage requirements and also increasing the weight of the plane. However, even if hydrogen is not used as a fuel itself, it will still play a big role in decarbonising aviation as it is an important input in the production of many SAFs. One such example is Power-to-Liquid (PtL) fuel. PtL fuels are formed by combining carbon and hydrogen together. Renewable electricity is used to remove carbon from CO₂ and H from water, making the whole process zero-carbon. The PtL technology is also at a mature technological readiness level (German Environment Agency, 2016).

Similar to SAFs in aviation, low-carbon fuels will play an important role in decarbonising shipping. The hydrogen products mentioned in literature as potentials fuels to decarbonize marine transport are ammonia and methanol. The biggest concern regarding these products is the relatively weak supply chain capabilities in Scotland when compared to the EU. An example of this is the weak shipbuilding supply chain and fewer active commercial shipbuilders of scale. Scotland is unlikely to be able to meet the demand for these fuels for even a small number of cargo vessels (Optimat and Scottish Enterprise, 2023). Security factors could be another possible concern with ammonia. Ammonia is a very toxic fuel, which should only be handled by qualified personnel. Despite their importance in decarbonising certain sectors, the current production of these products is limited. Therefore, more focus needs to be placed on increasing their supply.

Need for further research

Many studies have focussed extensively on analysing both demand- and supply-side factors of Scotland’s hydrogen and HDP sectors. However, our research found that there is not enough information about different geographical hubs in Scotland and the role they can play. The lack of individual focus on different hubs has motivated this study.

1. Supply chain capabilities of Scotland’s hydrogen hubs

Maximum potential renewable power generation

The maximum potential renewable power generation is defined as the total current, planned and announced installed capacity of solar PV and wind power projects in each hub region. Data was provided by council authority, so data was aggregated according to the defined council authority groupings for each hub. 2023 installed capacities were obtained from the DESNEZ Regional Renewable Statistics (2024). To obtain current capacity, this data was supplemented by projects that came online in 2024, as reported by the DESNEZ Renewable Energy Planning Database (REPD) and desk-based research (2024). Offshore wind projects were assigned to hubs based on their onshore landing points. The resulting current capacities were scaled by the 2023 average load factor for Scotland, appropriate to each technology (DESNEZ, 2024).

The REPD was also used to calculate planned installed capacity. From this database, development statuses encompassed under “planned” included:

• “Under Construction”.
• “Awaiting Construction”.
• “No Application Required”.
• “Application Submitted”.
• “Revised”.

For announced installed capacity, we included the 27.6 GW of ScotWind leasing round projects (Offshore Wind Scotland, 2024). The likely onshore landing point (and so corresponding hub) was identified from individual project websites. If this information was not available, the closest hub was allocated the offshore capacity. We included additional announced wind and solar projects from the Global Energy Monitor tracker (2025). To scale the resulting planned and announced capacities, we used load factors reported by DESNZ for UK new build projects (for delivery years 2026-2029) (2024).

To obtain the maximum potential renewable energy power generation for each hub, we then summed the current, planned and announced solar PV and wind power generation. We ranked the hubs from 1 (least generation) to 15 (highest), as shown in Table 13.

Table 12: Summary of data used for the calculation of maximum potential renewable power generation.

Table 13: maximum potential renewable power generation by hub.

Water availability

In 2022, Ramboll, on behalf of SGN, investigated water availability for green hydrogen production across Scotland (Ramboll, 2022). This estimated hubs’ maximum green hydrogen production potential based on current water availability and forecasted hydrogen production capacity for 2045.

Water availability was defined as the total volume of effluent water and fresh water, including groundwater, surface water and potable water. Sea water was excluded from the analysis as its availability is effectively unlimited and it is accessible to all Scottish hubs. To evaluate potential water availability, we took the difference between Ramboll’s forecasted green hydrogen production capacity and the maximum production potential for each hub.

To ensure a fair comparison, we used the same methodology and assumptions for Duisburg as for the Scottish hubs. Ramboll outlines this approach on pages 26–27 of their report

(2022). According to the Jülich research centre, Duisburg could have a maximum installed hydrogen capacity of 1 GW by 2050 (Cerniauskas, et al., 2021, p. 79). Since no specific data was available for 2045, we assumed that the installed capacity would be the same as in 2050.

The total water availability for hydrogen production in Duisburg is approximately 18,697,000 cubic metres. This includes:

• 2,697,000 cubic metres of non-used fresh water ( Statistische Ämter des Bundes und der Länder, 2025).
• 16,000,000 cubic metres of effluent water from central waste treatment plants (Wirtschaftsbetriebe Duisburg, 2025).

Based on Ramboll’s assumptions, green hydrogen production requires 10 kg water per kg hydrogen. Additionally, we should account for a 20% water loss. Using 2,697,000 cubic metres of fresh water, the maximum hydrogen production potential is approximately 1.5 million tonnes. This result was converted to kilowatt-hours (kWh) using the lower heating value for hydrogen (33.3 kWh). We estimated that Duisburg’s maximum hydrogen production potential is 14 GW using the following equation:

The assumptions for this calculation are detailed in Table 14. Finally, we calculated Duisburg’s water availability by taking the difference between its forecasted hydrogen production capacity and its maximum production potential.

The final rankings from 1 to 15 (with 1 representing the hub with the least water availability) are shown in Table 15.

Table 14: Summary of data used for the calculation of water scarcity.

Table 15: Raw data and rank for water availability by hub.

Gross Value Added of the energy sector

The Office of National Statistics (ONS) supplied data on the gross value added of the energy and the production sectors (2024). The ONS defined the production sector as SIC07 A-E. For the energy sector (including renewables), the ONS included the following SIC codes:

• SIC 05: Mining of coal and lignite
• SIC 06: Extraction of crude petroleum and natural gas
• SIC 09: Mining support service activities
• SIC 19: Manufacture of coke and refined petroleum products
• SIC 20.14: Manufacture of other organic based chemicals
• SIC 35: Electricity, gas, steam and air conditioning supply
• SIC 36: Water collection, treatment and supply
• SIC 38.22: Treatment and disposal of hazardous waste
• SIC 71.12/2 Engineering related scientific and technical consulting activities
• SIC 74.90/1 Environmental consulting activities

The GVA data by council area was aggregated to provide a hub-level view. Table 16 provides the data for GVA for each hub in the energy and the production sectors.

Table 16: Raw data and rank for GVA of the energy sector by hub.

Table 17: Summary of data used for the calculation of GVA of the energy sector.

Full time equivalent workers

The data for the current size of workforce in different hubs was taken from Skills Development Scotland. The data was broken down into 32 local authorities. We took the current workforce figures for the Energy and Engineering sectors. The numbers from relevant local authorities were then added to derive the final number for each of our hubs. Table 18 shows the current workforce stats for each hub.

Table 18: Size of workforce in the engineering and energy sectors of Scotland.

Future workforce requirement

The data for the future workforce requirement was taken from Skills Development Scotland’s database. This data was also disaggregated into 32 local authorities. The figures for all relevant local authorities were added to calculate final figures for our hubs. Table 19 shows the final estimates for future expansion demand.

Table 19: Estimated future expansion demand for each hub in Scotland.

Large-scale storage capacity

Currently, there are no commercial geological hydrogen storage projects in Scotland. So, we have assessed the technical geological storage capacity for each hub. For this, we have used estimates from scientific literature. The sources for each storage technology are detailed in Table 21. We assigned the storage capacities to each hub based on the site’s location or, if offshore, their likely terminal.

We normalised the total large-scale storage capacity for each hub to provide a score from 1-10 (highest capacity). We adjusted the scores of the following hubs by +0.25. This adjustment accounted for the possibility of developing offshore salt caverns and the planned Project Union pipeline that could connect hubs to English salt caverns.

• Aberdeen
• Dumfries and Galloway
• Dundee
• Fife
• Glasgow
• Grangemouth
• Moray
• Orkney
• Scottish Borders

The adjustment helped differentiate low-scoring hubs while maintaining the ranking integrity of those with confirmed storage capacity. Finally, we ranked the hubs from 1-15, where 15 represents the hub with the highest capacity (Table 20).

For Duisburg, we were unable to assess its specific technical storage capacity from scientific literature. However, compared to Scotland, Germany has hydrogen storage projects in the planning phase (Hornby, 2023). Due to the approved German core pipeline network, Duisburg will be connected to these projects. Therefore, due to higher confidence in hydrogen storage availability, we qualitatively assigned Duisburg a score of 3/10. This places Duisburg second to Aberdeen in the final ranking.

Table 20: Large-scale storage capacity by hub.

Table 21: Summary of data used for the calculation of large-scale storage capacity.

Pipeline network infrastructure

To score each hub’s potential pipeline infrastructure, we used the following scale from 1-6:

• There is no pipeline infrastructure suitable for hydrogen and no proposed or planned new hydrogen pipelines.
• There are existing gas pipelines which can be repurposed. There are no planned new hydrogen pipelines but there may be some proposed.
• There is a small-scale (e.g. distribution/spur pipelines) hydrogen pipeline project at any phase of development.
• There is a large-scale (e.g. trunkline pipelines) hydrogen pipeline project at any phase of development.
• The hub is a potential international export or import site for hydrogen and HDPs. However, planned pipeline infrastructure is insufficient and/or the site is not well-established for international trade.
• The hub is a potential international export or import site for hydrogen and HDPs. There is sufficient planned pipeline infrastructure, and the site is well-established for international trade.

We have detailed the justification and sources for each hub’s rating in Table 22. Using these ratings, the hubs were ranked from 1 to 15 (Table 23). 15 represents the hub with the most suitable pipeline network infrastructure.

Table 22: Scoring method for pipeline network infrastructure.

Table 23: Hub ranking for pipeline network infrastructure.

Ports

We have investigated which hubs are most suitable for meeting maritime shipping fuel demand and for trading hydrogen and HDPs by ship. To evaluate the scale of each hub’s maritime industry, we ranked the hubs based on their total port freight traffic in 2023. This analysis was based on the Department for Transport’s Port Freight Statistics Publication (Maritime Statistics, 2024). The Port0101 dataset breaks down freight traffic by port and council authority. Traffic included domestic and international freight traffic in both directions and we included all ports – major and minor. For Duisburg, we used State Office for Information and Technology NWR data for freight traffic in both directions for 2023 (2024).

We adjusted these initial ranked scores based on several criteria, shown in Table 24. For the port dimensions criterion, if online information was conflicting, we selected the greatest dimension for further scoring. This multi-factor scoring method reflects the diverse functions that ports serve. Based on these final scores, we ranked the hubs from 1 to 15 (Table 25). 15 represents the hub with the most suitable port infrastructure.

Table 24: Score adjustment criteria for scoring port metric.

Table 25: Summary of data used for scoring the port metric.

Table 26: Raw data, analysis and rank for ports by hub.

Local policy and planning support

The data for the local policy and planning support metrics were taken from Scottish government’s Planning Application Statistics database. The data was broken down into 24 local planning authorities. The data was taken from the relevant local authorities and averaged for all our hubs.

It was found that for the average success rate of applications, there was no data for 6 hubs. Table 27 shows the average success rate and average planning duration for each Scottish hub and Duisburg.

Table 27: Average success rate and duration for planning applications

Sensitivity analysis

For main report, we weighted capability groups according to the working group’s priorities and adjusted these weightings based on data confidence. We normalised each metric ranking from 1-15 into a 1-10 scale. Then, according to the defined weightings, we scaled the metric score for each hub to provide a total score out of 100.

Here, we analyse the sensitivity of this priority scoring by considering two alternative scenarios:

• The balanced scenario – all metrics are weighted equally at 9.1%.
• The absolute scenario – Rather than scoring hubs relatively according to metric rankings, we used the absolute data for each metric. For example, for GVA of the energy sector, we normalised the absolute GVA values to give a score from 1-10. The same weightings are used as in the priority scenario.

Table 28: Hub rankings from priority, balanced and absolute scenario.

Table 28 shows the final ranking for supply chain capability according to all three scenarios. Several key insights can be taken from our sensitivity analysis:

• We can see that the hubs at the ranking extremes remain the same. Aberdeen remains the top hub for supply chain capability, while the Western Isles and Argyll and Islands are the bottom hubs.
• The hubs between these extremes vary according to the scenario. However, the general “upper” (Cromarty, Glasgow, Fife, Grangemouth, Ayrshire) and “lower” (Dundee, Moray, Dumfries and Galloway, Shetland, Orkney and Scottish Borders) groupings identified in the priority scenario are consistent in the balanced and absolute scenarios.

1. HDP demand in Scotland’s hydrogen hubs

Demand mapping – e-methanol and ammonia for maritime

It is estimated that the UK used roughly 7 million tonnes of fossil marine fuels in the year 2021 (Transport & Environment, 2023). We used the EU Commission’s assumption of 40.5 MJ/kg as the energy content of marine fuel. Using this, we derived the addressable market for the whole of UK. Assuming that the fuel usage by Scottish ports will have the same share, we estimated the addressable market for Scotland’s maritime sector. Using data from the Department for Transport, we calculated the share of freight activity of each hub’s ports in the UK (Maritime Statistics, 2024).

Due to the uncertainties associated with estimating demand for individual HDPs in this sector, our analysis is technologically agnostic. We have not tried to estimate individual demand for each HDP. This analysis only estimated the addressable demand for all HDPs in the maritime sector of Scotland.

Table 29: Estimated shipping fuel demand by hub

Demand mapping – e-methanol for chemicals

In Scotland, we assume that Grangemouth Chemical Science Park is the only large-scale user of methanol as a chemical feedstock. We based this analysis on the estimated syngas produced from two onsite ethane crackers which supply INEOS’ polymer plants (INEOS Group, 2025). The ethane crackers have a production capacity of around 1 million tonnes of ethylene per year (Endeavor Business Media, 2016). From this value, we have reverse calculated the yield of syngas (hydrogen and methane from the crackers). Assuming an 80% yield of ethylene product, 1.25 million tonnes of ethane feedstock is required (Brooks, 2013). From literature, we can expect an estimated 13% yield of syngas (Brooks, 2013). This means 160,000 tonnes of syngas is produced from 1.25 million tonnes of ethane. In the production of petrochemicals, syngas is converted to methanol. Assuming 8600 hours/year of operation and a 62% yield, we can expect to produce around 100,000 tonnes of methanol (Timsina, et al., 2021). We then multiplied this result by the lower calorific value of methanol (19.9 MJ/kg) and the conversion factor of 2.78×10^-10to give the energy demand in TWh.

Demand mapping – SAF for aviation

We estimated the addressable market for SAFs in the Scotland by estimating the potential demand for jet fuel in each public airport in Scotland. Due to lack of data on jet fuel consumption in each airport, we took some assumptions to calculate potential demand. It is estimated that the UK used 11 million tonnes of jet fuel in the year 2022. This figure is for all the airports in the UK. So, to determine jet fuel demand for Scotland, we calculated the percentage of aircraft activity in each airport against the total UK aircraft activity. It was then assumed that the proprtion of jet fuel used in an airport will be the same as their share in total aircaft activity.

The table below show the proportion of aircraft movement in each hub and airport.

Table 30: Estimated jet fuel demand in all Scottish airports.

Demand mapping – ammonia for fertilisers

To estimate ammonia demand from fertilisers, we first estimated the total demand for nitrogen based fertilsers in Scotland. For our analysis, we assumed that nitrogen-based fertilisers consist of just urea and ammonium nitrate fertilisers. The fertiliser use estimation was done for both cropland and grassland. The average nitrogen based fertiliser application rate was taken from the UK government’s Fertiliser Use Database. The average application rate for nitorgen fertiliser in Scottish croplands is 120 kg/ha. And the average application rate for grassland is 83 kg/ha.

This average application rate was then multiplied by the total estimated crop and grass lands in Scotland. We then estimated the nitrogen content in these two fertilisers. After getting the nitrogen content in them, we estimated the demand for ammonia.

Once the final figure for ammonia was derived, we divided the total use of ammonia for all our hubs. This was done by assuming that each hub’s share of use of ammonia will be the same as their share of total GVA in agriculture. The table below shows our demand estimates for ammonia in each Scottish hub.

Table 31: Estimated ammonia demand from fertilisers in Scotland

1. Policy gap analysis

Table 32: Further information about all the policies and regulations we researched.

How to cite this publication:

Yip, E., Nagpal, D., Wilson, J., Morton, H. (2025) Scotland’s capabilities in producing hydrogen products and derivatives ‘, ClimateXChange. DOI: http://dx.doi.org/10.7488/era/6397

© The University of Edinburgh, 2025

Prepared by Talan 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 as at the date of the report, 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.

This work was supported by the Rural and Environment Science and Analytical Services Division of the Scottish Government (CoE – CXC).

ClimateXChange

Edinburgh Climate Change Institute

High School Yards

Edinburgh EH1 1LZ

+44 (0) 131 651 4783

info@climatexchange.org.uk

www.climatexchange.org.uk

1. 
   

   There are two types of estimated demand: replacement and expansion. Replacement demand refers to workers that will be needed to replace the current workforce. Expansion demand represents demand that will arise due to the growth in an industry. ↑

   
   

The Scottish Landfill Tax (SLfT), introduced in April 2015, was designed to discourage landfill disposal and encourage prevention, reuse, recycling and energy recovery.  

The tax has two rates. The lower rate of SLfT was designed to provide a low-cost disposal route for inert, low-risk materials, such as rocks and soils.  A higher standard rate targeted more polluting materials to support environmental goals. In early 2024, lower-rate materials exceeded standard-rate materials for the first time.

This research provides an initial evidence base to assess the effectiveness of the lower rate and explore whether changes could better support a low-carbon, circular economy. It examines the most common lower-rate materials, their environmental impacts, the feasibility of diversion and options for policy reform. 

The researchers conducted quantitative and qualitative data analysis, a literature review and stakeholder engagement. 

Findings

Three materials accounted for 77% of all waste landfilled at the lower rate in 2023–24, by weight:  

• mechanically-treated fines (small particles from treatment of general construction and demolition waste, municipal recyclate etc)
• soils and stones from construction waste  
• mechanically-treated mineral fines (small particles from treatment of naturally-occurring materials such as rocks and soils, silt, clay, sand and stones, found in quarry, construction and demolition waste etc) 

Mechanically-treated fines make up the greatest quantities of all lower-rate materials, despite being intended as a residual output from material recovery processes. Trends raise concerns regarding misclassification. 

Environmental impact analysis, based on the quantities landfilled in Scotland, showed that these three materials also have the highest impacts across indicators such as air pollution, water use and resource scarcity.  

This study suggests the lower-rate SLfT may be only partially aligned with Scotland’s current circular economy, waste prevention and climate goals. While it has supported some diversion of inert waste from landfill, it may also be driving unintended behaviours and limiting investment in recovery.

Both fiscal and non-fiscal actions may be needed to address these challenges. The upcoming Scottish Aggregates Tax and wider circular economy policy agenda offer opportunities to align SLfT more closely with long-term environmental objectives. 

For further details, please read the report.

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

Podcast and blog

Susan Evans and Richard Claxton give an overview of the project and findings in episode 17 of our podcast: Evidence for climate policy in Scotland

A blog post summarising the podcast interview is also available on our website: Project snapshot: Reviewing the landfill tax

Image credit: WOKANDAPIX from Pixabay

Research completed May 2025

DOI: http://dx.doi.org/10.7488/era/6063

Executive summary

The Scottish Landfill Tax (SLfT), introduced in April 2015, was designed to discourage landfill disposal and encourage prevention, reuse, recycling, and energy recovery.

The tax has two rates. The lower rate of SLfT was designed to provide a low-cost disposal route for inert, low-risk materials, such as rocks and soils. A higher standard rate targeted more polluting materials to support environmental goals.

In early 2024, lower-rate materials exceeded standard-rate materials for the first time. Along with shifts in policy priorities and a widening gap between the lower and standard tax rates, this raises questions about whether the lower rate remains aligned with the Scottish Government’s environmental objectives.

Aims

This research provides an initial evidence base to assess the effectiveness of the lower rate and explore whether changes could better support a low-carbon, circular economy. It examines the most common lower-rate materials, their environmental impacts, the feasibility of diversion and options for policy reform.

We conducted quantitative and qualitative data analysis, a literature review and stakeholder engagement.

Findings

Priority materials

We found that three materials accounted for 77% of all waste landfilled at the lower rate in 2023–24, by weight:

• mechanically-treated fines (small particles from treatment of general construction and demolition waste, municipal recyclate etc.)
• soils and stones from construction waste
• mechanically-treated mineral fines (small particles from treatment of naturally-occurring materials such as rocks and soils, silt, clay, sand and stones, found in quarry, construction and demolition waste etc)

Mechanically-treated fines make up the greatest quantities of all lower-rate materials, despite being intended as a residual output from material recovery processes. Trends raise concerns regarding misclassification and (from our interviews) of intentional production.

Environmental impact analysis, based on the quantities landfilled in Scotland, showed that these three materials also have the highest impacts across indicators such as air pollution, water use and resource scarcity.

The classification of lower-rate materials is complex. The European Waste Catalogue (EWC) codes used by industry do not directly align with SLfT qualifying categories. Moreover, some codes encompass a range of material compositions depending on their source. Mechanically-treated fines are diverse in composition, originating from various construction waste materials. Soils and stones from construction waste, though better defined, also pose classification and compliance challenges. Mechanically-treated mineral fines tend to be more uniform.

Waste prevention and landfill diversion options

Soils and stones are often reused on-site or in restoration, though off-site reuse is constrained by regulation, logistics, and project timing. Options for recovering and re-using mechanically-treated fines are limited, due to contamination and variable composition. The recovery of mechanically-treated mineral fines is easier than the recovery of non-mineral fines but the cost and technical barriers make the use of virgin materials a simpler option.

Upstream measures in the construction sector may have more impact than attempts to recover and re-use waste. Such measures might include improving waste source segregation, designing for reuse and avoiding demolition. While such interventions are technically viable, they are limited in practice by weak incentives, inconsistent standards, and market barriers.

Policy assessment

The SLfT interacts with several fiscal and non-fiscal policies, both existing and on the horizon. These include the upcoming ban on biodegradable municipal waste to landfill; Scottish Aggregates Tax and Digital Waste Tracking, both expected in 2026 (DEFRA, 2023). Based on the assessment of diversion options for the priority materials, we highlighted various fiscal and non-fiscal policy options for future consideration.

Conclusions

This study suggests the lower-rate SLfT may be only partially aligned with Scotland’s current circular economy, waste prevention and climate goals. While it has supported some diversion of inert waste from landfill, it may also be driving unintended behaviours and limiting investment in recovery. Both fiscal and non-fiscal actions may be needed to address these challenges. The upcoming Scottish Aggregates Tax and wider circular economy policy agenda offer opportunities to align SLfT more closely with long-term environmental objectives.

Key areas for further exploration could include:

• Raising the lower SLfT rate to incentivise application of the waste hierarchy.
• Assigning a new SLfT rate to mechanically-treated fines, to address misclassification and recognise its relatively high environmental impacts.
• Strengthening enforcement and guidance on material classification to reduce compliance risks.
• Build on existing cross-border regulatory and enforcement cooperation to address ongoing challenges such as waste tourism and the evolution of the landfill tax.

This research is relevant to the Scottish Government, Revenue Scotland, SEPA, and others involved in the design or enforcement of fiscal and waste management policy, as well as stakeholders in the construction, demolition and waste processing sectors.

Glossary / Abbreviations table

Introduction

Research context and aims

The Scottish Landfill Tax (SLfT) was introduced in April 2015, following the devolution of landfill taxation under the Scotland Act 2012. It replaced the UK Landfill Tax in Scotland and was designed to discourage landfill disposal and encourage adherence to the waste hierarchy. This hierarchy prioritises prevention, reuse, recycling, and energy recovery over landfill.

The tax is collected and administered by Revenue Scotland and has two rates. The standard rate, which covers materials more likely to pollute the environment or generate greenhouse gas (GHG) emissions, will be £126.15 per tonne in 2025-26. The lower rate is £4.05 per tonne as of April 2025 (Revenue Scotland, 2024b). The lower rate applies to materials considered to have low GHG emissions, limited pollution risks, and no hazardous properties when landfilled. For instance, ceramics, glass, soil and stones, and various mixtures of inert materials. Both rates were raised incrementally each year from 2015-16 to 2024-25, and increased by around 24% in April 2025-26 (Revenue Scotland, 2024a).

However, there is a large, widening gap between the rates, and the criteria and conditions for setting them have remained unchanged since 2016. This prompts questions about whether the lower rate continues to align with Scotland’s evolving environmental priorities. It also offers opportunities for policy development, which this research explores. The timing of this study is particularly relevant: a UK Government consultation on landfill tax reform is underway at the time of the publication of this study, concluding in July 2025 (HM Treasury and HMRC, 2025). Moreover, in 2024, the Welsh Government implemented an increase to its lower rate. These developments signal a wider shift in approach across the UK, and this research aims to inform future decision-making in Scotland as part of that wave of change.

Tonnages of landfilled waste have steadily declined over the past decade, but standard rate materials have dropped fastest. In early 2024, the quantity of lower rate materials exceeded that of standard rate materials for the first time. Figure 1 shows the gap between standard rate material (in orange) and lower rate material (in teal) has narrowed in the last 5 years. The widening gap between the lower and higher tax rates has also increased concerns about whether this is driving waste misclassification and crime. It is hard to determine a clear trend related to the landfilling of lower rate material in the years since 2020.

Figure 1: Tonnes of taxable waste declared by quarter in Scotland (source: Revenue Scotland)

The upcoming ban on landfilling biodegradable municipal waste, effective from the end of 2025, is expected to accelerate this trend (Scottish Government, 2022). It is therefore timely to focus in on lower rate materials to assess if SLfT is still serving its purpose. The Scottish Government has committed to explore whether changes may be needed to this or related policy levers, to support progress towards a low-carbon, circular economy (Scottish Government, 2024a).

The SLfT intended to support Scotland’s environmental objectives, which include

• Reducing the volume of waste sent to landfill.
• Lowering GHG emissions.
• Minimising pollution risks in landfill environments.
• Promoting the application of the waste hierarchy.

Scotland’s waste and resources policies have evolved since the landfill tax was introduced. They are now strongly oriented towards the objectives set out in the Circular Economy (Scotland) Act 2024 and the Circular Economy and Waste Route Map to 2030 (Scottish Government, 2024a). These provide a framework for increasing resource efficiency and reducing reliance on landfill. Specific information on these can be found in Appendix A.

The Route Map commits to developing a residual waste plan to 2045 and reviewing materials currently landfilled to identify alternative management routes by 2027. The SLfT legislation allows for additional lower rates to be created in support of future policy (Scottish Government, 2022).

Scotland’s net zero targets and biodiversity strategy were introduced in light of the twin climate and biodiversity crises. They have reinforced the need for waste and resources policies that support decarbonisation across all sectors. Most environmental impacts associated with resource use take place before materials are disposed of. A circular economy, with an emphasis on resource efficiency and waste prevention, is therefore essential for meeting Scotland’s environmental objectives. SLfT should be evaluated in this context, considering not only tonnages landfilled but the whole-life environmental impacts of materials.

Project objective, aims and research questions

The overarching objective of this research is to evaluate the effectiveness of the lower rate of SLfT in supporting Scotland’s environmental policy objectives. These policy objectives include reducing the volume of waste sent to landfill, lowering GHG emissions, minimising pollution risks, and encouraging materials to move up the waste hierarchy.

This research supports policy development by assessing whether the lower rate of SLfT remains effective in advancing Scotland’s environmental objectives. It also examines whether adjustments to the tax or related policy levers could accelerate progress towards these objectives. Specifically, this study aims to:

• evaluate the effectiveness of the lower rate in supporting Scotland’s environmental goals;
• identify the lower-rate materials that have the greatest environmental impact;
• explore waste prevention and diversion options for lower-rate materials and their feasibility;
• assess key barriers to reducing reliance on lower-rate landfill disposal;
• examine how the SLfT interacts with other fiscal and non-fiscal waste and environmental management policies and identify areas for future research and policy interventions.

To achieve these aims, the following research questions are addressed:

• Which materials landfilled at the lower rate rank the highest in terms of quantity and negative environmental impacts?
• What diversion options and alternative treatments exist for these materials, and how feasible are they in light of technical, market, and policy barriers?
• What are the key barriers to reducing the volume of materials landfilled at the lower rate, and how can they be addressed?
• How does the SLfT intersect with other fiscal and non-fiscal waste management and environmental policies, and what options exist to strengthen policy?

This report provides an initial evidence base for discussions on potential changes to the lower rate of SLfT. It does not present a cost-benefit analysis of policy options. It highlights the highest-impact materials and presents opportunities to divert from landfill, noting key barriers.

These findings aim to contribute to ongoing policy discussions and future research,

in support of Scotland’s transition to a low-carbon, circular economy.

Methodology

This study was conducted from December 2024 to March 2025 by Resource Futures and Aether, in collaboration with a steering group comprising the ClimateXChange research lead and representatives of the Scottish Government, SEPA and Revenue Scotland. It followed a three-stage approach (see Figure 2).

We designed the methodology to provide an initial evidence base to progress policy development. Robust data analysis was used to identify key materials and focus future research. Key materials were determined based on impact.

Figure 2: Research approach

We used quantitative and qualitative data analysis, a literature review, and stakeholder engagement to support this approach. Table 1 below summarises each research stage and corresponding data collection methods. These are further detailed in Appendices B and C.

Table 1: Data collection methods by research stage

In the first stage, we assessed tonnage and environmental impacts data on materials landfilled at the lower rate. This enabled us to prioritise the top three material streams.

We analysed tonnage data by EWC code, or groups of codes where necessary. This relied on data obtained from SEPA and Revenue Scotland. To assess environmental impacts, we used the Scottish Waste Environmental Footprint Tool (SWEFT). This covers a range of environmental indicators, including GHG emissions, resource depletion, and pollution potential (Zero Waste Scotland, 2024). We refined our understanding of the top material streams, through engagement with waste management operators, industry experts, policymakers, and the project steering group.

In the second stage, we examined opportunities to move lower-rate materials up the waste hierarchy. A high-level literature review identified prevention, reuse, recycling, and recovery options, assessing their technical feasibility. Stakeholder interviews provided further insights into potential diversion options and barriers to these.

In the final stage, we reviewed how the lower rate of SLfT interacts with related policies. We used desk-based research to review other relevant measures and draw comparisons with landfill taxation in other jurisdictions. Engagement with policymakers and regulators provided insights into how the tax operates in practice. We identified areas where further research is needed to address gaps or unintended consequences.

For the stakeholder engagement, we conducted eight in-depth, semi-structured interviews, and gathered additional insights via email, in January to March 2025. Further details of the methodology, including the stakeholder engagement, can be found in Appendix C.

Quantitative data review to determine priority materials

This section sets out how we identified the three highest-impact material streams taxed at the lower rate, which are assessed in more detail in Sections 5 and 6.

We first give a summary of the process for preparing and classifying waste for landfill in Scotland (Section 4.1). We then present findings by weight based on Revenue Scotland and SEPA data (Section 4.3) then on the weighted environmental impact of materials (Section 4.4). This forms the basis for prioritising lower-rate materials summarised in Section 4.5.

Introduction to classifying and preparing waste for landfill in Scotland

For waste to be landfilled in Scotland, waste producing businesses must follow a structured process to ensure compliance with environmental regulations. This process involves multiple parties, including waste producers, skip operators, transfer station operators, landfill operators, and regulators such as SEPA and Revenue Scotland.

Key steps in preparing waste for landfill include:

• Waste identification – determining the type of waste based on its source, composition, and potential hazards.
• Waste characterisation – including chemical analysis and testing (where required) to assess hazardous properties and biodegradability.
• Waste classification – the waste is assigned a European Waste Catalogue (EWC) code by the waste producer. EWC codes must be included on waste transfer notes (for non-hazardous waste) and hazardous waste consignment notes. These documents accompany waste during its movement and disposal and are checked by waste carriers, site operators, and regulators.
• Pre-treatment and landfill acceptance requirements – including necessary treatment to reduce environmental impact, compliance with landfill permit conditions, and landfill waste acceptance criteria (WAC) testing, where required.
• Documentation and record-keeping – maintenance of records, results and transfer documentation to ensure legal compliance.

Two key documents to support businesses in meeting these obligations are:

• Waste Classification Technical Guidance (WM3) (SEPA et al, 2015): The guidance, co-produced by SEPA, Natural Resources Wales, Northern Ireland Environment Agency, and Environment Agency, provides comprehensive instructions on identifying whether waste possesses hazardous properties.
• Criteria and Procedures for the Acceptance of Waste at Landfills (Scotland) Direction 2005 (Scottish Government, 2012a): The document gives criteria and procedures for waste acceptance at landfills, ensuring compliance with environmental standards. WAC are described in the accompanying ‘Schedule’ to this Direction.

SEPA holds responsibility for governance of compliance and therefore holds national level data on the transfer and treatment of waste into, within, and out of landfills in Scotland. As regulator of the SLfT, Revenue Scotland holds parallel data obtained through tax returns. The anonymised data from Revenue Scotland, alongside SEPA’s, underpins the analysis presented in the following section.

While many elements of the landfill preparation process are legal requirements, some practices – such as separating certain materials for recovery – are strongly encouraged by regulators or industry bodies due to viable diversion routes or market demand. These distinctions are important context for the findings presented later in this report.

Overview of waste data analysis

This section presents a summary of analysis performed on waste tonnages data provided by SEPA, and SLfT returns data from Revenue Scotland which was anonymised for the purposes of this study. The data provided by SEPA and Revenue Scotland are categorised by EWC code (European Commission, 2000). These data insights can be used to help progress policy development.

EWC codes are a list of waste descriptions used in all UK nations and EU member states. However, as explained in detail in Section 5.3, EWC codes do not directly correlate to SLfT rates. EWC codes must be used on waste transfer notes and hazardous waste consignment notes. The submission of waste transfer notes also comes with ‘operator descriptions’ to further explain the EWC code categorisation. There are around 650 individual codes split across 20 ‘chapters’. The chapter typically defines the industry or source of waste; however, some definitions are more material- or process-based. Despite the large library of codes, some remain broad in scope. This means that use of the EWC codes within a dataset does not automatically achieve transparency or traceability in terms of material definitions.

For this report, descriptors have been adopted for each EWC code, or group of codes, present within the lower-rate tonnages data provided by Revenue Scotland. These are outlined in Table below.

Table 2: EWC codes within the lower tax rate in Scotland

We ranked the data from Revenue Scotland on lower-rate waste to landfill by weight. Data from SEPA for each matching EWC code, or group of codes, was then used to identify the amount of each material landfilled at lower rate as a proportion of the total landfilled. This allowed for prioritisation based on overall tonnage of lower rate material. Further information on steps for data cleansing and review is provided in Appendix B.

Results show the largest quantities landfilled in Scotland by material (at both lower and standard rate), in the financial year 2023 to 2024, were soil and stones, mechanically-treated fines and mechanically-treated mineral fines.

It is important to note that the data presented does not account for exemptions, meaning the reported tonnages are likely an underestimate of the actual quantities of waste generated. Exemptions are highlighted later in the report throughout Sections 6 and 7.

Figure 3 below highlights how the ranking changes when considering only materials landfilled at lower rate (in teal) with results for standard rate material also shown (in orange). The top three materials by weight are:

1. 19 12 12: Mechanically-treated fines (fine particles left over from mechanical waste processing)
2. 17 05 04: Soil and stones (non-hazardous soils and stones from C&D waste)
3. 19 12 09: Mechanically-treated mineral fines (fine particles of minerals, e.g. sand and stones, left over from mechanical waste processing)
4. These three materials make up 77% of the material landfilled at lower rate in 2023-24. The analysis shows that most mechanically-treated fines and mechanically-treated mineral fines are landfilled at the lower rate. In comparison, only a small portion of soil and stones is landfilled at the lower rate.

Figure 3: Tonnage of waste to landfill at standard and lower tax rates by EWC code, 2023-2024.

Analysis of waste quantities and composition data

We identified short-term trends for each material. We also reviewed operator descriptions in the SEPA data to better understand the materials and their origins. Summaries are presented for the three material groups landfilled in the greatest quantities at the lower rate of tax. These are presented in order with the highest tonnage first.

Mechanically-treated fines: EWC 19 12 12

This non-hazardous material group contains fine particle rejects from mechanical waste processing, including sorting, crushing, pelletising and compacting, as well as a minority share of anaerobic digestion residue. A more detailed description is provided in Section 5.1.

Approximately 60% of mechanically-treated fines were landfilled at the lower rate of tax in 2023-24. As shown through SEPA and Revenue Scotland data in Figure 4 below, the overall quantity landfilled has decreased over the most recent three-year period. However, the quantity landfilled at lower rate (in teal) has increased, while the quantity landfilled at standard rate (in orange) has decreased.

For context, the quantity landfilled under the lower rate was consistently under 200,000 tonnes before 2020. This increased sharply to a peak in 2022-23, before declining slightly again in 2023-24, but remaining well over pre-2020 levels.

Figure 4: Tonnage of waste to landfill at standard and lower tax rates for the three priority materials from 2021 to 2024.

Soils and stones from construction waste: EWC 17 05 04

The soils and stones EWC code group is for non-hazardous materials and results from construction and demolition waste. It is restricted to topsoil, peat, subsoil and stones only. Therefore, soil waste classification testing must take place to determine if soils are non-hazardous or inert (qualifying for the lower rate), or hazardous (standard rate). More information is provided in Section 5.2.

Approximately 21% of soils and stones was landfilled at the lower rate in 2023-24. Figure 4 shows that both the total quantity landfilled (ie the combined teal and orange bars), and the quantity landfilled at lower rate (in teal), have decreased from a 2021-22 peak. As a result, the portion of this waste group landfilled at the lower rate has remained stable over the most recent three years.

Based on the operator descriptions submitted with the waste transfer notes, this EWC material group contained just over 12,000 tonnes (2.2%) of ‘contaminated’ soil in 2023-24. It should be noted that contaminated is not equivalent to ‘hazardous’. Descriptions of this EWC code attached to records of larger waste quantities simply state “contaminated soil” with no further specificity. Descriptions accompanying some of the smaller quantities of lower-rate waste have mention of contamination by Japanese knotweed.

In addition, around 10,000 tonnes (1.8%) was recorded as having traces of asbestos in 2023-24, almost entirely from one waste record. This was much higher than any records mentioning traces of asbestos for previous years.

These findings highlight uncertainty around the application of WAC testing to this code. Soil and stones containing hazardous substances may potentially have been misclassified under the non-hazardous code 17 05 04, instead of its hazardous counterpart, 17 05 03. From stakeholder interviews, it is understood that misclassification is likely to contribute to the large quantity of soil and stones being disposed of under this material group.

Mechanically-treated mineral fines: EWC 19 12 09

This material group is classified as fines from naturally occurring rocks and soils, silt, clay, sand and stones. It is non-hazardous. A more detailed description is available in Section 5.1.

76% of this material group was landfilled at the lower rate of tax in 2023-24, which was similar to the portion in 2022-23. Looking further back, the quantity landfilled at lower rate peaked at just over 120,000 tonnes in 2019-20, before a significant decline in the following two COVID years. Quantities landfilled at the lower rate have bounced back slightly but not to pre-COVID levels.

As shown in Figure 4 above, this material group is landfilled in proportionally greater quantities under the lower rate (in teal) than the standard rate (in orange).

Baseline environmental impact of materials

We used Zero Waste Scotland’s SWEFT data to provide a high-level assessment of how the materials landfilled at lower rate may impact the environment. This enabled us to check whether any lower-tonnage material groups warranted further attention due to their disproportionately higher environmental impacts.

The tonnages for 2023-24 were multiplied by lifecycle-based SWEFT factors. Lifecycle-based SWEFT factors consider the entire environmental impact of a material, from extraction to disposal, which helps assess its true ecological footprint. This produced a weighted impact for each material group against each of SWEFT’s six environmental indicators. Further information on methods and assumptions in application of SWEFT is provided in Appendix B.

Because SWEFT factors covers a range of environmental impacts, they cannot be aggregated into a single, comparable “score”. To visualise and compare relative impacts, we used a spider diagram (see Figure 5), which presents the results for the top six material groups landfilled at lower rate in Scotland during 2023-4.

Figure 5 below shows that the top three material groups by tonnage also have the greatest environmental impacts. These materials – mechanically-treated fines, soil and stones, and mechanically-treated mineral fines – are shown in the colours teal, dark orange and black respectively .

Mechanically-treated fines are estimated to have the largest weighted impacts on air pollution, mineral resource scarcity, water consumption and land use. Soil and stones, and mechanically-treated mineral fines, have the next-highest impacts for the same indicators.

One mixed material group (shown in light orange) scores highest on GHG emissions and biodiversity. However, this group, was found to be almost entirely made up of drill cuttings in 2023/24 based on operator descriptions within the SEPA data. As a result, we chose to describe this as a niche material (see Table 2). This results in a high environmental impact but with high uncertainty.

No other material groups were flagged as priorities for further research based on this high-level analysis of environmental impacts. As such, the three lower-rate material groups landfilled in highest quantities were prioritised for further research.

Figure 5: SWEFT tool results presented by material and relative environmental impact (only top six scoring material groups are shown)

Priority materials and supporting interview data

From the analysis of tonnage landfilled and environmental impact assessment, three material groups were prioritised: soils and stones, mechanically-treated fines, and mechanically-treated mineral fines. These materials accounted for 77% of lower-rate landfilled waste in 2023-24 and had some of the highest environmental impacts, particularly on air pollution, resource scarcity, and land use.

Grouped codes of niche materials were excluded due to data limitations: (i) they consist of multiple waste types with varying, and unknown, compositions and quantities, and (ii) the lack of specificity meant the assessment of environmental indicators relied more on generalised assumptions.

Focusing on the three dominant materials enabled targeted research into impactful interventions to reduce landfill and improve resource recovery. This selection was also verified through analysis of interviewee responses. For example:

• Mechanically treated fines, mechanically-treated mineral fines and soils and stones were confirmed as the main materials: “They are the majority of materials in the lower rate.” (Commercial remediation company interview); “A lot of the lower rate material will essentially be fines.” (C&D waste management processor)
• Most high-quality materials are already reused in construction: “The only reason construction companies take things off sites now is because they can’t use it.” (C&D skip operator)
• Mechanically-treated fines come from transfer stations and skip waste: “Mechanical fines come from transfer stations and sorting of skips waste. Skip operators generate the majority of the fines in the Scottish market.” (Commercial remediation company)
• Mechanical-treated fines create challenges for waste management: “Mechanically-treated fines are the top waste we question whether the rate is right.” (SEPA interview) and “we tend to stay away from mechanically-treated fines, because the administration and risk of misclassification sits with us.” (Commercial landfill operator)

Complexities in the categorisation of priority materials

Determining when a material qualifies for the lower rate is not straightforward. This is due to the complex properties of the lower-rate materials, the sources of these materials and the different classification systems used in policy. To aid in understanding, this section outlines what the three priority material streams comprise, the sources of these materials and their link to categorisations in Scottish policy.

Mechanical fines: EWC 19 12 12 and 19 12 09

Two of the priority materials, mechanically-treated fines and mechanically-treated mineral fines, belong to the same EWC chapter 19 12. This chapter refers to waste from the mechanical treatment of waste, for example sorting, crushing, compacting or pelletising (Dsposal, n.d.). These are commonly referred to as trommel fines, or mechanical fines (typically 10-40mm).

Fines that qualify for the lower rate under both waste codes largely come from construction and demolition (C&D) waste and, therefore, share similar diversion options and barriers which are discussed in Section 6. The term ‘mechanical fines’ is used hereafter as shorthand when these two categories of fines are discussed together.

The key distinction between the codes is their composition:

• Mechanically treated mineral fines (EWC 19 12 09): Primarily from excavation and mechanical treatment of quarry waste, C&D waste, and aggregate recycling (WRAP and Environment Agency, 2013). Composition is relatively uniform.
• Mechanically treated fines (EWC 19 12 12): Includes fines from mixed C&D waste, municipal recyclate, and residual waste. Fines qualifying for the lower rate are primarily from mixed C&D waste due to higher inert content (Di Maria et al., 2013; Vincent et al., 2022). Composition is far more varied.

The interview findings and other data suggest that mechanical fines – whether classified under EWC 19 12 09 or 19 12 12 – are commonly produced at transfer stations and through the mechanical sorting of skip waste, particularly when handling C&D material. Composition is mostly crushed bricks, tiles, concrete, and ceramics – similar to mineral fines (the same as mechanically-treated mineral fines). However, the code can also include additional inert materials, including fines from the mechanical treatment to recycle furnace slags, bottom ash, and plasterboard to recover gypsum^[3] (Environment Agency, 2023a; Environment Agency, 2023b).

To summarise, both types of mechanical fines may contain a small amount of contamination and non-qualifying material, but can still be eligible for the lower rate if they meet the conditions set out in Article 4 of the 2016 Order. To qualify, fines must either consist entirely of qualifying material or contain only a minimal amount of non-qualifying material, must not be artificially mixed or hazardous under WM3, and must pass the Loss on Ignition (LOI) test with a result of 10% or less (Revenue Scotland, n.d.). Otherwise, they are subject to the standard rate.

Some waste producers intentionally misclassify mechanical fines to avoid the higher rate of tax, using blending techniques to bring LOI values down (Ali, 2023; SEPA, C&D waste management processor interview, commercial landfill operator interview). Many small- to medium-sized skip operators handle this waste, making enforcement difficult (waste industry association and commercial remediation company interview).

Soils and stones from construction waste: EWC 17 05 04

The EWC code 17 05 04 refers to non-hazardous soils and stones from C&D waste (including excavated material from contaminated sites) (Dsposal, n.d.; Environmental Standards Scotland, 2024; Katsumi, 2015; Commercial remediation company interview; C&D waste management processor interview). In Scotland, this material becomes waste after removal from a site. It can be used for work on site without being classified as waste.

Soils and stones require multiple tests. They must be classified as hazardous or non-hazardous following the WM3 classification. When subjected to testing it is likely for other materials to be found, which could make the soil active (non-inert), such as grass. Unless the contaminating materials are in small amounts and pass the soil LOI test, the whole load will be charged the standard rate. Non-hazardous soil and stone can only be disposed of in inert landfill sites and charged the lower rate if a WAC test confirms this is appropriate. A WAC test will determine the leaching ability of any contaminants in the soil.

Misalignment in waste code and policy guidance

This section compares EWC code definitions (Dsposal, n.d.), Revenue Scotland guidance (Revenue Scotland, n.d.), and SEPA guidance (SEPA, 2015) for the three priority materials.

The Scottish Landfill Tax (Qualifying Material) Order 2016 determines which materials qualify for the lower tax rate. There are seven groups of materials which qualify for the lower rate. However, these seven qualifying material groups and EWC codes do not align. This allows material to be classed as standard or lower rate under a single EWC code, as seen in the analysis of waste quantities (Section 4.3). Such misalignment is common in other jurisdictions in the UK and beyond with the widespread use of EWC codes and varying landfill policies.

Table 3 below presents a systematic review of the EWC codes for the priority three materials against other categorisations in Scottish policy. This provides a more specific, detailed understanding of these material streams.

Soils and stones (EWC 17 05 04) are the most straightforward to categorise, aligning clearly with Group 1 (Rocks and soils) and with no additional SEPA definitions or overlaps.

In contrast, mechanically treated fines (EWC 19 12 12) are the most complex to classify. As discussed in Section 5.1, this code can encompass materials across all seven qualifying groups, depending on source and composition, making consistent classification more challenging and reliant on testing and operator descriptions.

Table : Alignment of priority EWC codes with SLfT and SEPA definitions

Waste prevention and landfill diversion options

In this section, we outline findings on the end-of-pipe and upstream diversion options for the three priority materials described in Section 5: mechanically-treated fines, mechanically-treated mineral fines, and soils and stones. A preliminary feasibility assessment of these technologies is also presented.

‘End-of-pipe’ diversion options involve reprocessing materials that have already been classified as waste, to divert them from landfill. ‘Upstream’ diversion options entail keeping materials at their highest value and reducing waste generation. For mechanical fines, this means preventing C&D waste from being mechanically treated (for example, keeping bricks as bricks). For soil and stones, it involves direct reuse.

We use the term ‘mechanical fines’ where the diversion options relate to both mechanically-treated fines and mechanically-treated mineral fines.

Mechanical fines: End-of-pipe diversion

This section outlines the diversion options and associated barriers for mechanical fines.

As some common challenges were identified, Section 6.1.1 first identifies overarching barriers relevant to all the diversion options. These barriers provide essential context for Sections 6.1.2 to 6.1.5.

Overarching barriers

Due to their complex and variable composition and technical processing requirements, mechanical fines are difficult, risky and costly to recover. According to a waste management company representative interviewed, currently only large- and medium-sized regional players are able to recover a proportion of mechanically-treated fines.

• Material complexity (technical barrier): Mechanical fines contain mixed materials, sometimes requiring washing to remove contaminants (Burdier et al., 2022). Differing physical and chemical properties, including composition and size, affect the feasibility of end-of-pipe recovery (Hernandez Garcia et al., 2024). This is further impacted by Scotland’s wet climate, which reduces the effectiveness of dry screening technologies (as highlighted in research conducted by Ricardo for ClimateXChange, due to be published in summer 2025). Composition testing to match materials to diversion options is expensive. Virgin materials are often easier and cheaper to use.
• Contamination (health and safety barrier): Heavy metals in some mechanical fines pose health and safety risks, limiting recovery (Oujana & Sanchez, 2018). Washing removes some contaminants (Vincent et al., 2022), but can create toxic wastewater and solid waste requiring further treatment (Cottrell, Ali and Etienne, 2024). The circularity benefits should be weighed against the resources and power needed to wash and process fines.
• Processing infrastructure (operational barrier): Washing plants remove silt and clay to produce clean aggregate. However, washing systems are expensive and often require bespoke designs so they do not clog processing systems, reducing efficiency (Vincent et al., 2022; C&D waste management processor interview). Stakeholders cite uncertain policies and tax implications as barriers to investment (C&D waste management processor, C&D skip operator and SEPA interviews).
• LOI testing (health and safety and regulatory barrier): LOI determines whether fines qualify for the lower rate tax or if they can be reused (interviews with C&D waste management processor and Commercial landfill operatorSUEZ). One interviewee reported that use of LOI tests to achieve end-of-waste status for mechanical fines was not permitted by SEPA due to its uncertain composition:

“We tried for a couple of years to get end-of-waste status on this material because some of the material, it does look really good and it would serve a purpose in further aspects of construction. But they’re very adamant that it’s a big no, because of the testing and because this material doesn’t come from a single source. You can’t test it as a single source, so it’s a bit of an unknown.” (C&D waste management)

• Liability (enforcement barrier): The current liability structure is a barrier to diversion, as it places the risk of misclassification on landfill operators rather than waste producers. This reduces producers’ incentive to ensure accurate classification or pursue upstream diversion. With no direct repercussions, producers can intentionally or unintentionally misclassify mechanical fines as lower-rate material (see Section 5.3).

The following sections detail end-of-pipe diversion options for mechanical fines, noting more specific barriers to mechanically-treated mineral and mechanically-treated fines where relevant.

Landfill/quarry cover, engineering and restoration

Inert mechanical fines are used for engineering and landscaping, such as quarries and pavement base layers, or for daily landfill cover. There is demand in Scotland for such uses, particularly due to a shortage of soils and stones (commercial landfill operator interview). While this can support diversion from landfill, it can waste nutrient-rich fines that might be better suited for agricultural use (Renella, 2021).

Recycled aggregate

Mechanically-treated mineral fines can be stored on site for six months and reused as aggregate without a waste licence under the Waste Management Licensing (Scotland) Regulations 2011 (schedule 1, paragraph 19). Mechanically-treated fines do not qualify for this exemption, however, and SEPA does not include them as waste suitable for the manufacture of recycled aggregate (SEPA, 2013).

Recycled aggregates (from crushed bricks, ceramics, and concrete) are used in roads, railways, and non-structural concrete production. Their carbon footprint can be lower than virgin aggregates when transport distances are short (ClimateXChange and Ricardo, 2025).

Reducing the environmental impact of concrete through recovery of inert fines has received a lot of research interest. For example, in 2023, 934 publications about reuse of clay waste (e.g. brick powder) in cement mixtures were published (Hernández García, Monteiro and Lopera, 2024). Studies suggest the material could replace 10-20% of virgin sand in non-structural concrete (Mansoor, Hama, Hamdullah, 2024; Ali, 2023; Zhao, et al., 2020). Despite the diversion potential for fines, innovations have not been scaled up commercially as virgin aggregates are favoured (European Commission, 2023).

Barriers:

• Recycled aggregates have different properties to natural aggregates and suit only low to moderate strength concrete (European Commission, 2023; Ali, 2023; Transport Scotland et al., 2020; commercial landfill operator interview; Ferriz-Papi and Thomas, 2020).
• Fine material can be inappropriate for some filling activities. For example, fines can be too smooth for use in layers for road-based applications (Burdier et al., 2022). It could be beneficial to consider other diversion options that suit these physical properties, such as reuse in paint to improve grip, rather than invest in technologies to change them.
• Quality and supply of fines are inconsistent (European Commission, 2023).
• Despite a high concentration of wash plants in Scotland (C&D waste management processor interview), mechanical fines require further space and infrastructure investment to be diverted to precast or ready-mixed concrete plants (European Commission, 2023).
• Wet fines from wash plants require more cement in concrete mixtures, increasing resource use and cost (commercial remediation company interview). Raw material and energy savings from using recycled aggregate need to be balanced against these impacts.
• The lack of market uptake of recycled aggregates is likely due to a lack of know-how by concrete producers and trained personnel for recycled aggregates production (ClimateXChange and Ricardo, 2025; European Commission, 2023; Hernández García, Monteiro and Lopera, 2024).

Land treatment and agricultural soil improvement

Inert mechanical fines can improve land, for example, by stabilising soil through land remediation or as a fertiliser for agriculture (Manning and Vetterlein, 2004; Burlakov, et al., 2021; Ali, 2023). This could be a positive diversion option for mechanically-treated mineral fines that are less useful for construction purposes (Renella, 2021).

Mechanically-treated fines can help replenish nutrients to the soil and reduce reliance on commercial fertilisers (Braga et al., 2019; Szmidt and Ferguson, 2004; Campe, Kittrede and Klinger, 2012). By mixing these fines with organic materials, they can create a soil-like material for plants to grow in. Some fine particles, like clay, silt or ash, help keep the organic matter stable (Haynes, Zhou and Weng, 2021; Renella, 2021).

Mechanically-treated fines contain a mixture of these materials. However, the UK Government restricts the use of soil substitutes made from mechanically-treated fines as opposed to mechanically-treated mineral fines (Environment Agency, 2023b). This can only be done under specific permits, such as for landfill restoration schemes, and when ecological improvement is also demonstrable.

In Scotland, under the Waste Management Licensing (Scotland) Regulations 2011 (schedule 1, paragraph 9), exemptions allow the use of mechanically-treated mineral fines on land for agriculture and ecological improvement. Waste companies in Scotland sometimes use mineral fines from skips to create compost for local agriculture (C&D skip operator interview). SEPA, who registers such activities, has reported that this exemption often results in farmers being paid to accept such waste to reduce landfill disposal costs (SEPA interview). However, it is uncertain how much is used for genuine purposes, and how much is diverted to avoid paying tax (C&D waste management processor interview).

Barriers:

• Silt and clay fines, which are beneficial for soils, are generally landfilled and this is because of high contamination of heavy metals or presence of organic materials (Renella, 2021).
• Nutrient content varies, limiting predictability of composition and related cost savings for farmers. For example, recycled mechanical fines with high nutrient content can reduce costs by 25%, whereas those with low nutrient content may increase costs by 9% (Braga et al., 2019).
• Potential conflicts with regulation on fertilisers. For example, UK government restricts the use of soil substitutes made from mechanically-treated fines (Environment Agency, 2023b) and new EU regulations may exclude some fines from fertiliser use (Renella, 2021).

Gypsum fines recycling

Gypsum fines (within EWC 19 12 12) can be recovered from plasterboard and used to make new plasterboards, cement, blocks and bricks (commercial landfill operator interview; Suárez, Roca and Gasso, 2016). Gypsum can also be used to improve soil in land remediation, particularly in areas with alkalinity or heavy metal contamination. SEPA advises that this is acceptable for treating land that has been flooded by seawater (SEPA, n.d).

Waste owners are encouraged to separate gypsum from other waste for recovery, as there are feasible diversion options and “because there’s a good recycling market for gypsum” (waste industry association interview). However, according to a commercial landfill operator, the composition of mechanically-treated fines “tends to be quite high in plasterboard and gypsum, which then means that we struggle to control the gas and the odours”. Gypsum can only be disposed of in landfills where no biodegradable waste is accepted as it has hazardous properties, releasing gas and odour, when mixed with biodegradable waste (commercial landfill operator interview).

When the ban on biodegradable waste to landfill is introduced at the end of 2025, it will potentially make the lower-rate landfill of mechanically-treated waste containing gypsum easier. Additional incentives for diversion to counter this could be necessary.

Barriers:

• Recycled gypsum has high market demand, but the lower rate categorisation encourages landfill over recycling (waste industry association interview, commercial remediation company interview, commercial landfill operator interview).
• Heavy contamination of mechanical fines restricts the potential to find and extract gypsum (Suárez, Roca and Gasso, 2016).
• Lack of incentives to enhance sorting of gypsum and plasterboard; and conversely incentives to process waste products containing gypsum into mechanical fines to qualify for the lower-rate tax (commercial landfill operator interview).

Mechanical fines: Upstream diversion

This section describes the upstream diversion options involving the reduction and reuse of concrete, bricks, tiles and ceramics. These options can prevent mechanical fines from being generated in the first place.

Reducing demolition through refurbishing and retrofitting

Refurbishing or repurposing buildings and assets extends their usable life, avoiding the generation of demolition waste. In doing so, it helps reduce both material use and embodied carbon, making it a key strategy for sustainable construction.

Lifecycle analysis (LCA) is a valuable tool for comparing the impacts of refurbishing and retrofitting with demolition and new build. While new builds may achieve lower operational carbon, they usually require more materials and result in more embodied carbon emissions. In many cases, this means retrofit has lower emissions overall.

Adopting a retrofit-first approach can reduce unnecessary demolition, prioritising reuse unless structures are severely derelict or face irreparable structural issues (Green Alliance, 2023; construction company interview). To support this, pre-demolition assessments could be introduced earlier in the planning process, ensuring that any proposed demolition is justified in terms of carbon and material impacts (Green Alliance, 2023).

Barriers:

• VAT policy favours new builds (0%) over renovations (20%) (Green Alliance, 2023).
• Current policies focus on reducing operational emissions, such the Heat in Buildings Strategy to increase energy efficiency (Scottish Government, 2021a), rather than embodied carbon emissions (Green Alliance, 2022).
• Circular principles are underused in construction and infrastructure, such as rail infrastructure projects (O’Leary, Osmani and Goodier, 2024).

Reduction and reuse of construction materials

Reducing demand for materials in the design stage has the greatest impact on reducing the environmental impact of construction (Green Alliance, 2023). This is particularly important for cement, which is challenging to remove from a building for reuse. Reduction and reuse can be increased through circular construction tools and approaches, sometimes described as ‘modern methods of construction’. These can improve companies’ understanding of GHG emissions throughout their supply chains. Examples include modular buildings, digital tools such as material passports, offsite manufacturing, and sustainable material substitution (Green Alliance, 2023).

Barriers:

• Current circular building standards are voluntary, such as the UK Net Zero Carbon Building Standard, and the Scottish Government’s Net Zero Public Sector Buildings Standard (Scottish Government, 2021b; UK Net Zero Carbon Building Standards, n.d.). Construction design is determined by the client. With voluntary initiatives, cost factors are more likely to win over environmental factors (Construction company interview).
• There are no mandatory requirements for construction companies in Scotland to conduct an LCA or report scope 3 emissions (those in its upstream and downstream value chains, which typically include the majority of material-related impacts) (construction company interview; Green Alliance, 2022).
• Skills shortages and inconsistent standards, for instance for LCAs and product passports, limit the sector’s ability to apply circular practices (Hurst and O’Donovan, 2024; construction company interview).
• Certain industry practices lead to unnecessary waste. For example, to ensure they have enough supply, contractors will often order 5-10% surplus, which can be hard to reuse (construction company interview).
• Sustainable construction materials often cost more (construction company interview).
• Environmental benefits of modern methods of construction are not fully accounted for in public procurement and other financial investment opportunities (Green Alliance, 2023).

Designing for deconstruction

Designing buildings with future disassembly in mind allows more materials, especially bricks and tiles, to be reused instead of downcycled. Such direct reuse has a greater impact in reducing raw material use than recycling (Green Alliance, 2023). However, deconstruction should only be pursued if the building is not fit for repurposing (construction company interview).

Early sorting of demolition materials also improves recovery outcomes. Many mechanical fines are produced from mixed, unsorted demolition waste, which results in variable and lower-quality outputs. Sorting materials earlier produces cleaner, inert fines that are more straightforward to reuse (C&D waste management processor interview, SEPA interview).

A major barrier to recovery and recycling of mechanically-treated fines is their complexity and variability (Section 6.1.1). To minimise the challenges associated with this, upstream measures should support sorting at source, before waste reaches skips or waste transfer sites (C&D waste management processor interview, SEPA interview). Greater source separation would generate more inert-only fines, which are also easier to find uses for due to waste management exemptions.

Barriers:

• Mainstream current and historical construction practices do not design for deconstruction (Arup and Ellen McArthur Foundation, 2020).
• Investors are not incentivised to incorporate circularity principles in design, considering material recovery (Arup and Ellen McArthur Foundation, 2020).
• Demand for low-quality recycled aggregate (Section 6.1.2) takes the focus away from higher-quality recycling and reuse.
• Integrated C&D tools and requirements for identifying, classifying and certifying salvaged materials are lacking (construction company interview).

Soil and stones: End-of-pipe diversion

This section explores the end-of-pipe diversion options for soils and stones from construction waste (EWC 17 05 04). End-of-pipe diversion options are concerned with when the material is classified as waste, and is then reprocessed into another material. As there are many exemptions for soil and stones reuse, the main diversion options are upstream, occurring before waste classification. The main end-of-pipe diversion option is to produce recycled aggregates.

Recycled aggregates

Soils can be washed to separate sand, gravel, and stone from contaminants, especially on brownfield sites, and reused as aggregate in construction (Magnusson et al., 2015; Choi et al., 2018; waste industry association interview).

Barriers:

• Recycled aggregate is more expensive than virgin materials (Magnusson et al., 2015; commercial remediation company interview). Quarrying for natural aggregate is cheaper and more accessible (commercial remediation company and waste industry association interviews).
• Soil remediation technologies are not widely used in Scotland (C&D skip operator interview).
• Fluctuations in cost and quality lead to inconsistent demand, impacting the feasibility of supply. For example, a facility failed in 2016 due to lack of demand (commercial landfill operator interview). There is good supply in Scotland of recycled quarry materials, but demand is low (commercial remediation company interview).
• There is low industry understanding of how to use recycled aggregates. For example, road projects where the ground is damp tend to require natural aggregates; recycled aggregates are more applicable for farm tracks, because they meet requirements for tractors more easily than cars (C&D skip operator interview).
• There is a higher recycling and reuse rate for soils and aggregates on site; what is taken off site tends to be less usable (C&D skip operator interview).

Soil and stones: Upstream diversion options

This section covers how soils and stones can be kept on site or reused at another site under exemptions, avoiding classification as waste.

Landfill/quarry cover, engineering and restoration

Soils and stones are used for temporary or final landfill cover, haul roads within a site, and restoring quarry sites. In landfill restoration, layers of subsoil and topsoil must be added, to enable development of vegetation (SEPA, 2018).

In Scotland, exemptions from SLfT apply under the Waste Management Licensing (Scotland) Regulations 2011 (Schedule 1, paragraph 9). This relates to where soil and stones treat land for agricultural or ecological benefit. Soil and stones are not subject to the same per-hectare limits for infilling agricultural land as other waste types (Waste Management Licensing Regulations, Schedule 2, paragraph 2), making it easier to divert them in larger quantities.

Barriers:

• Fewer landfills are operational. The number has declined since 2005 (SEPA, 2023) and this is expected to reduce further after the ban on landfilling biodegradable municipal waste (interviews with commercial remediation company; waste industry association; large public body).

Landscaping and construction

On-site reuse of soils reduces transportation and storage issues, making it the most cost-effective option (commercial remediation company interview). Transfer to another work site requires a waste management licence or exemption. Exemptions apply where soils and stones are used to treat land, provided certain conditions are met (Waste Management Licensing (Scotland) Regulations 2011, Schedule 1, Paragraph 7).

SEPA has issued regulatory guidance to support the sustainable reuse of greenfield soils which are soils from undeveloped, uncontaminated land. The soil must be used for a specified purpose, identified before excavation begins, and transfer must be approved by SEPA. Purposes may include the operational land of railways or land which is woodland, park, garden, verge, landscaped area, sports or recreation ground, churchyard or cemetery.

Interviewees indicated that practices for coordinating soil reuse in Scotland vary between projects based on developers (commercial remediation company and engineering consultancy interview). Public sector contracts sometimes include reuse requirements, while private contracts typically show less incentive. Carbon considerations are an emerging driver for on-site reuse, where these materials are less ideal than virgin quarry materials but still meet requirements (engineering consultancy interview).

Barriers:

• The UK has over 700 soil types requiring thorough classification by type (topsoil/subsoil) and hazard level (hazardous/non-hazardous, active/inactive) prior to reuse (The Royal Society, 2020; Soil Association, 2021).
• Mismatches in soil type, availability, project timelines, and storage requirements often hinder reuse (Thompson, 2021; Choi et al., 2018; Hale et al., 2021; Marasini et al., 2012; SEPA, commercial remediation company and engineering consultancy interviews).
• Geography and pressure to keep heavy vehicle movements off community roads incentivises finding reuse options close to sites of origin, but timing can prevent this (engineering consultancy interview).
• In some cases, the SLfT can have less negative financial impact on a project than costs of storage, transport, or project delays, making reuse impractical (engineering consultancy interview).
• Reuse of soil and stones may be deprioritised compared to the sustainability of manufactured materials like concrete (Berryman et al., 2023) especially where time and budget constraints apply (commercial remediation company and engineering consultancy interviews).
• Reuse options for contaminated soils are limited. Untreated soil is costly to landfill, while treated soil is typically restricted to low-grade uses such as embankments (engineering consultancy interview).
• Liability concerns discourage topsoil reuse as developers and landowners remain responsible for future environmental impacts (Hale et al., 2021).
• Multiple compliance pathways such as exemptions, permits, and definition of waste protocols create confusion, increasing the risk of non-compliance, misclassification, and illegal disposal (commercial remediation company interview; Thompson, 2021).
• Despite Berryman’s et al. (2023) guidance aimed at harmonising best practice, industry uptake remains inconsistent. The absence of a unified legislative framework results in varied approaches across agriculture, land development, engineering, and land management sectors (Thompson, 2021).

Preliminary feasibility assessment of diversion options

This section presents an indicative assessment of the viability of different waste diversion options for the three priority materials: mechanically-treated fines (19 12 12), mechanically-treated mineral fines (19 12 09), and soils and stones (17 05 04). The assessment considers how feasible the diversion options currently are. This includes information on current use, research and development activity, and the barriers mentioned above in section 6.

The feasibility score therefore indicates the extent that future interventions are needed to target barriers and enable diversion. The feasibility scoring is as follows:

• 1 = Not currently feasible, would require significant intervention to upscale.
• 2 = Feasible to some extent, some barriers would need to be addressed.
• 3 = Most feasible, already happening widely in Scotland.
• n/a = not applicable, didn’t come up as a diversion option for the material in the research.

The methodology behind this assessment can be viewed in Appendix D.

Tables 4 and 5 below present the preliminary feasibility assessment of the end-of-pipe and upstream diversion options. For reference we also include a general impact rating of the technology based on the findings from desk-based research and stakeholder interviews. The impact rating reflects the overall environmental and circular economy benefits (e.g. quantities of materials diverted from landfill) that could be achieved if the option were implemented more widely, using a simple scale of ‘high’, ‘medium’ or ‘low’.

Key takeaways of the assessment are:

• Mechanically-treated fines have a limited number of feasible end-of-pipe solutions at present. Landfill cover and gypsum recycling are technically possible, but most other downstream options score low on feasibility and offer only low to medium impact. As a result, it is likely better to prioritise upstream interventions – such as deconstruction, modular construction, and refurbishment – for their higher impact potential, even though they are not yet widely adopted.
• Mechanically-treated mineral fines have more feasible end-of-pipe diversion options, including reuse in land restoration and aggregate recycling. These options are already in operation and could be scaled further considering the opportunity to provide ecological improvements so maximum value is retained.
• Soils and stones show the greatest feasibility overall, particularly for recycled aggregates and reuse in landscaping. While some remediation technologies are not yet fully developed, most of the downstream options are already in use.
• Gypsum and plasterboard recycling is moderately feasible and could play a larger role with better separation and recovery at source.
• Upstream interventions such as modular construction, deconstruction, and refurbishment, score high on impact across all materials where relevant, but face barriers related to investment, data, and planning. Technological readiness is improving – especially with AI-driven solutions for sorting and design – and deployment is likely to increase in the next 5–10 years with the right incentives and digital infrastructure.

Table : Preliminary feasibility assessment of end-of-pipe diversion options

Table 5: Preliminary feasibility assessment of upstream diversion options

Key (see the methodology above for more information)

Policy assessment

This section provides an overview of existing policies influencing the management and diversion of the three priority materials. It also identifies policy gaps and presents potential interventions discussed in previous sections to enhance waste diversion, aligning with Scotland’s environmental objectives. 

Overview of existing policies 

Several key policies and fiscal mechanisms shape the management and disposal of the priority materials in Scotland. Some policies are devolved to the Scottish Government, while others are reserved, under UK Government control. These policies shape the incentives and barriers encountered by waste producers and processors in diverting materials from landfill. 

Fiscal measures 

Scottish Landfill Tax (SLfT), the focus of this study, is devolved legislation introduced in 2015 to reduce the environmental impacts of waste, encouraging waste reduction and adherence to the waste hierarchy in Scotland. While standard-rate SLfT has risen significantly to £126.15 per tonne in 2025-26, the lower rate (£4.05 per tonne in 2025-26) remains considerably lower, as is broadly the case in the rest of the UK. As discussed, this lower rate is applied to seven groups of qualifying materials (Section 5.3), typically inert or less polluting wastes such as some construction and demolition waste. The lower-rate aims to provide an economic incentive for their diversion from landfill while avoid imposing undue costs on sectors where alternative treatment options may be limited.

The Aggregates Levy (AGL) is a UK-wide tax applied to commercially exploited (virgin) crushed rock, sand, and gravel to encourage the use of recycled alternatives. A Scottish Aggregates Tax (SAT) is expected to replace the UK AGL from April 2026, offering an opportunity to explore ways to further incentivise the use of secondary aggregates (Scottish Government, 2024b).  

The Climate Change Levy (CCL) and Carbon Price Floor (CPF) are UK-wide fiscal measures designed to reduce carbon emissions by taxing energy use and setting a minimum price for carbon from electricity generation (HM Revenue and Customs, 2024). While these policies primarily lead to emissions reductions (Döbbeling-Hildebrandt et al. 2024, p.2) they also indirectly affect waste management across the UK by incentivising energy efficiency and low-carbon industrial processes.   

Other regulatory measures 

The Waste (Scotland) Regulations 2012, which are devolved secondary legislation, require waste producers to prioritise prevention, reuse, and recycling over landfill disposal (Scottish Government, 2012b). Businesses must segregate recyclable materials to improve recycling rates (Zero Waste Scotland, 2023). While these regulations reinforce waste hierarchy principles, they do not specifically address lower-rate waste streams. 

The upcoming ban on biodegradable municipal waste (BMW) to landfill, effective 31 December 2025, is a devolved Scottish Government policy aimed at reducing environmental impacts from organic waste. While this ban will primarily impact standard-rate waste (Scottish Government, 2022), it could have indirect consequences for certain lower-rate materials. Minerals, and soils and stones, traditionally used for landfill engineering purposes, may see temporarily higher demand for use in landfill closures, but a long-term decline in demand. Alternative diversion pathways would be needed for these to align with Scotland’s circular economy objectives. In addition, gypsum, which currently can only be landfilled at sites without bio-waste, is likely to become easier to landfill. There may also be an increase bio-based mechanically-treated fines from municipal waste streams. Increased enforcement of fines’ classification and incentives for recycling may therefore be required. However, the ban will not signal the complete end of bio-waste to landfill, as it includes certain exemptions.

Digital Waste Transfer Notes (WTNs), a UK-wide initiative, aims to improve traceability and enforcement by transitioning to an electronic system for recording waste movements (DEFRA, 2023). This system aims to reduce the misclassification of waste, including lower-rate materials like mechanically-treated fines, by providing greater transparency in the movement of waste. It is expected to “shine a light on transactions and actors” currently missing from the system, while enhancing compliance with landfill tax regulations (CIWM, 2023). The April 2025 roll-out has recently been postponed to April 2026. 

These are the key fiscal and regulatory policies interacting with lower-rate materials. However, gaps remain in their effectiveness for supporting diversion options for the three categories of waste which make up the bulk of lower-rated waste in Scotland notably mechanically-treated fines, soils and stones, and mineral waste. Addressing these gaps could involve targeted interventions, as discussed in the following sections and Appendix A.  

Policy gaps and potential interventions 

Despite existing regulatory and fiscal policies, several policy gaps hinder the effective diversion of lower-rate materials from landfill, such as mechanically-treated fines, and soils and stones from construction. These gaps are categorised according to their relation to either end-of-pipe waste management or upstream prevention in the material life-cycle.

This section outlines potential interventions to address such gaps. These are not policy recommendations but options to consider. Further research, analysis and consultation would be required before deciding whether to take any, or all, forward.

End-of-pipe diversion 

Compliance risks and landfill misclassification

A key enforcement challenge is misclassification of waste at landfill sites. The widening gap between standard- and lower-rate SLfT (now standing at above £100 per tonne in 2025-26) may have inadvertently created financial incentives for waste producers to classify waste as lower-rate whenever possible. Along with the complex classification criteria (see section 5.3), this may have led to both deliberate and unintentional misclassification, particularly for mechanically-treated fines. 

Rather than being residual outputs of material recovery, large quantities of fines are purposefully produced to qualify for the lower rate (Section 6.1.1). This distorts waste tracking data and results in potentially recoverable material being landfilled.

Landfill operators hold tax liability for misclassification, even though they do not generate or pre-process the waste. This creates financial risks for operators, leading some to refuse lower-rate fines altogether. 

Ambiguity in classification raises costs for both regulators and waste operators. Waste producers may unintentionally misclassify waste due to lack of clear, standardised guidance, leading to incorrect application of the lower tax rate (see Section 7.2.1.1).  Although better guidance could reduce some misclassification, it is unlikely to fully resolve the issue. This is because the underlying rules that determine whether fines are subject to the lower or standard rate are themselves complex and difficult to apply consistently, particularly when mapped against EWC waste code classifications (see Section 5.3). Clearer guidance may help reduce ambiguity, though it may also be worth exploring whether simplification of the tax qualification rules could support more consistent classification.

A recent SEPA report on the BMW-to-landfill ban notes that sorting residues from processing municipal waste (including mechanically-treated fines) may be generated in greater volumes in order to bypass the ban (SEPA, 2024a). This risks undermining the intent of the bio-waste ban policy through reclassification rather than genuine diversion. This risk is supported by our findings about the production of mechanically-treated fines to qualify for the lower rate (Section 6.1.1).

Potential fiscal interventions: 

• Explore the feasibility of a specific tax rate for mechanically-treated fines which is much closer to the standard rate, or reclassification under the standard rate. This could discourage excessive fines production while retaining the lower rate for less problematic inert materials. A careful balance would need to be struck to avoid unintended consequences, particularly for businesses reliant on landfill for inert waste management. Supportive measures, addressing upstream value chains, would likely be needed.

Potential non-fiscal interventions

• Technical: Review LOI testing requirements to ensure they do not deter investment in fines processing, while maintaining environmental safeguards (C&D waste management processor interview; waste industry association interview; C&D skip operator interview).
• Enforcement: Explore the potential for enhanced regulatory oversight through the upcoming digital waste transfer notes (WTNs) system to track and verify waste classification at source rather than at landfill. Through this, tax liability for misclassified mechanical fines could be shifted to the company which produced the fines, even if this is discovered after it has been accepted at landfill, along with penalties for misclassification.
• Other: Improve guidance on EWC code classification by providing clearer criteria to support consistent decisions on whether waste qualifies for the lower rate. This could include practical examples of lower-rate materials, decision trees, and alignment with the upcoming digital waste transfer note system. In the longer term, there may also be value in exploring whether simplifying the underlying rules on lower-rate material classification could further reduce classification ambiguity.

Separation and recovery of mechanically-treated fines 

Inadequate pre-sorting of C&D waste leads to contamination and fines production. Once contaminated, fines are difficult to reprocess. Industry practices in Scotland and globally do not sufficiently prioritise separation at the source, meaning valuable materials are lost to landfill. 

Potential fiscal interventions:

• Continue strengthening incentives to increase the demand for recycled fines. This is already starting with the planned introduction of the Scottish Aggregates Tax in April 2026 which will initially align with the UK Aggregates Levy. Over time, there may be scope for policy divergence in Scotland. Additional financial incentives – such as tax breaks or recycled content requirements – could drive up industry circularity, such as for reused material content, recycled material content and reusable materials (Green Alliance, 2023). However, interventions would have to avoid unintended consequences related to availability of recycled fines. This could be a particular issue in rural areas, which are further from recycling infrastructure (commercial remediation company interview).

Potential non-fiscal interventions: 

• Technological: More support for technologies and infrastructure to reprocess fines and reduce contamination could help address issues with fines in washing facilities. Programmes like the Knowledge Transfer Partnership could play a role. Existing examples include phytoremediation, which uses plants and microorganisms to degrade pollutants and reduce heavy metals (Yadav et al., 2022).
• Technological: Technologies exist to make the shape of fines coarser and more suitable for construction purposes, though the outputs are currently more costly than natural aggregates (C&D skip operator interview). Further reuse routes could be explored, for example how to promote fine aggregates being added to paints for flooring to increase traction.
• Regulatory: Encourage early-stage waste management planning by integrating material audits into construction permitting. This includes site investigations, sampling and testing to support effective use of recycled aggregates.
• Other: Improve industry understanding of recycled fines through guidance and awareness campaigns, including how and when they can be reused (C&D skip operator interview).

Cross-border waste movement risks 

SLfT operates within a broader UK framework, presenting cross-border waste movement compliance challenges. For instance, if Scotland increased its lower-rate SLfT while England maintained the current lower rate, waste exports may increase, undermining the tax’s effectiveness as well as Scottish tax revenues. Similarly, restricting mechanical fines’ eligibility for the lower rate in Scotland could lead to this waste stream being diverted to England instead of being recovered. 

These risks are particularly relevant in light of recent and proposed changes across the UK. As mentioned, the Welsh Government increased its lower rate of Landfill Disposals Tax in 2024, and the UK Government is currently consulting on significant reforms to Landfill Tax in England and Northern Ireland, with the consultation due to conclude in July 2025 (HM Treasury and HMRC, 2025).

Introducing financial or enforcement-based interventions is challenging in a cross-border context. The Scottish Government has limited or no authority over waste processed or disposed of in other UK jurisdictions.

Potential fiscal interventions:

• Considering penalties for cross-border misclassification, similar to Wales’ Unauthorised Disposals Tax (150% of the standard rate) and the proposal in the UK government’s consultation (200% of the standard rate) which creates an additional financial deterrent for people seeking to dispose of waste illegally. 

Potential non-fiscal interventions: 

• Regulatory/enforcement: Enhancing regulatory and enforcement coordination between Scotland, England, and Wales to ensure greater policy consistency and prevent waste tourism. 

Upstream diversion

Reducing reliance on landfill also requires preventing lower-rate materials from being generated as waste. However, this is constrained by limited incentives for circular practices, inconsistent reuse standards, weak producer responsibility measures and insufficient integration of circularity in planning and procurement.

Lack of incentives for designing in circularity

Soils, stones, and minerals removed from C&D sites are often generated, and classified as waste, without efforts to improve their quality or assess their reuse potential. This results in unnecessary landfill disposal, despite available prevention and recovery pathways. Lack of guidance on soil and stone classification, combined with inconsistent reuse standards, means that secondary materials markets remain underdeveloped.

Mechanically-treated fines are often the result of poor material selection at the design and procurement stages. If more construction materials and products were designed for disassembly, reuse, or easier sorting, rather than demolition, the production of fines could be significantly reduced. Currently, there is no strong economic driver for waste producers to prioritise clean, separable materials over mixed waste streams that result in fines.

Current planning regulations and public procurement rules do not sufficiently integrate circular economy principles. Without upfront material assessments, valuable materials are classified as waste and disposed of unnecessarily.

The UK and the devolved nations are moving toward more comprehensive extended producer responsibility (EPR) schemes for other materials. If an effective system is adopted for construction, this could encourage producers to adopt circular practices and reduce waste generation at the design stage. There have also been sub-national developments in London, where large planning applications for approval by the mayor now require whole lifecycle carbon assessments, carbon reduction plans, and circular economy statements. Before a redevelopment or demolition plan can be approved, an audit must be carried out to determine the reuse potential of materials in the existing building (Mayor of London, 2022).

Circular economy policies such as these are needed to transition the construction sector as a whole, changing value chains so that much less of the priority materials in this study are generated. The lower rate of SLfT could be iteratively increased in tandem with these interventions, as a supporting measure; if it were to be raised too rapidly without supporting upstream interventions, negative impacts on the construction sector and on illegal disposal would likely occur.

Potential fiscal interventions:

• Consider raising the overall lower rate of SLfT to provide a greater incentive for circular practices on construction sites. Even a relatively modest increase could help to justify the costs of storing and transporting materials such as soils and stones for reuse (engineering consultancy interview). Wales’ new lower rate (£6.30 per tonne) could serve as a benchmark. A rate of £6 per tonne was deemed viable by industry interviewees (commercial landfill operator and C&D waste management processor).
• Consider monitoring the development and impacts of the upcoming Scottish Aggregates Tax (SAT), which will replace the UK Aggregates Levy from April 2026. While the SAT will be limited to the commercial exploitation of aggregates as defined in the 2024 Act (Scottish Government, 2024b), its introduction provides a useful opportunity to review whether taxation influences the quantities of lower-rate aggregates sent to landfill. Insights from this review could help inform future considerations around the treatment of other virgin materials used in construction, within the context of devolved powers and existing legislative frameworks.
• Consider financial incentives for reuse in construction, such as tax relief for projects incorporating secondary materials (construction company interview).
• Ensure SLfT exemptions support the diversion of lower-rate materials from landfill. A review of existing and upcoming exemptions, for instance with the bio-waste to landfill ban, may help assess their effectiveness in facilitating prevention, reuse and recovery while maintaining environmental protections.
• Consider engaging with HM Revenue and Customs over VAT reform, such as extending zero-rate VAT to refurbishment and retrofit to reduce incentives for demolition and new build construction.

Non-fiscal interventions

• Policy: Consider the expansion of EPR to cover construction materials, shifting financial responsibility for waste management onto producers to encourage modular design and reuse.
• Policy: Consider mandatory, rather than voluntary, circularity requirements targeting construction project clients (construction company interview). Investigate opportunities to strengthen public procurement rules to prioritise secondary materials, reuse, spoil management and design for deconstruction. These requirements could support more systematic waste prevention at the planning stage and drive investment in circular practices (SEDA, 2024; O’Leary, Osmani and Goodier, 2024).
• Policy: Consider reforms to embed circularity in planning policy, such as requirements for pre-demolition assessments, material recovery assessments before deconstruction and resource management plans to include deconstruction design (Construction company interview; Green Alliance, 2023).
• Policy: Explore adoption of carbon reporting tools that account for lifecycle emissions, including embodied carbon and Scope 3 (SEDA, 2024). Distinct reuse and recycling reporting for high-impact materials like concrete may also help reduce downcycling (Green Alliance, 2023).
• Technological: Consider supporting the development of product passports or material databases for construction materials to improve transparency and enable reuse (construction company interview).
• Technological: Consider the future use of AI and matching platforms to optimise design and reuse coordination (Huang et al., 2022; Choi et al., 2018; construction company interview).
• Operational: Consider investigating early-stage site audits, sampling and testing to support on-site recovery and reuse of recycled aggregates (C&D skip operator and engineering consultancy interviews).
• Operational: Consider the potential for construction material hubs to store and redistribute soils and other surplus materials. However, barriers remain around ownership, quality control, certification and fraud risk (commercial remediation company and construction company interviews).
• Other: Consider aligning government strategies on housing and urban development with circular economy targets to create long-term demand for reused materials (Green Alliance, 2023).
• Other: Consider investing in training and awareness to support greater uptake of recycled aggregates and reused soils. Cultural shifts may be needed to encourage viewing soil and stones as valuable resources, rather than ‘dirt’ (Thompson, 2021; Berryman et al., 2023).

Addressing both end-of-pipe and upstream barriers will be essential for improving SLfT effectiveness and enhancing material recovery. As with other areas of circular economy policy, coordinated packages of measures working across material value chains, targeting incentives at multiple stakeholders, are likely to be needed. By considering these policy measures, Scotland could identify strategies to reduce landfill reliance, improve material efficiency, and accelerate its transition to a circular economy.

Conclusions

This section summarises the key findings of the research and assesses whether the lower-rate SLfT remains effective in supporting Scotland’s environmental and waste management objectives. It also considers the broader policy implications, including potential enforcement challenges, unintended consequences, and cross-border impacts.

Summary of key findings

The lower rate of SLfT was introduced to enable the cost-effective disposal of low-risk, inert waste while ensuring compliance with Scotland’s broader environmental policies. Overall landfill trends show a mild downward trend in landfilled lower-rate materials at least until early 2020 (Figure 1), suggesting the tax may have initially influenced disposal patterns. Tonnages of lower rate material to landfill have since fluctuated without a clear trend (Figure 1). This research identifies several factors that may influence the continued effectiveness of the lower rate:

• Lower-rate landfill disposal is dominated by three specific waste streams—mechanically-treated fines, soils and stones, and mechanically-treated mineral fines—which together accounted for 77% of all lower-rate waste landfilled in 2023-24.
• Mechanically-treated fines are landfilled in the greatest quantities out of all lower-rate materials, and have seen the greatest increase in quantities between 2021-2024 (with a slight dip in 2022-23). This is despite originally being intended as residual outputs from material recovery processes. This trend raises concerns over misclassification and evidence from our interviews of fines being produced on purpose.
• Environmental impact analysis highlights that mechanically-treated fines pose significant risks, contributing disproportionately to air pollution, resource depletion, and biodiversity loss compared to other lower-rate materials.
• Current SLfT structures, fiscal incentives, and policy measures are not effectively supporting higher-value diversion options for lower-rate materials. The relatively affordable lower tax rate continues to make landfill the most economically attractive option for many waste producers of the priority materials, as it does in some other parts of the UK.
• The upcoming ban on BMW (effective December 2025) will change landfill dynamics, reducing long-term demand for materials traditionally used in landfill engineering, and may lead to more lower-rate materials being sent to landfill.
• Misclassification of waste remains a major issue, exacerbated by complex EWC code classifications that do not always align with SLfT qualifying material criteria. The lack of easy-to-use guidance and strong oversight contributes to both deliberate and unintentional misclassification.

These findings suggest that while the lower-rate SLfT has played a role in reducing landfill disposal overall, there may be opportunities to better align it with Scotland’s evolving circular economy and net zero ambitions.

Does the lower rate of Scottish Landfill Tax (SLfT) still support Scotland’s environmental objectives?

The lower-rate SLfT was designed to provide a cost-effective landfill option for inert, low-risk materials while supporting Scotland’s environmental policies, including waste reduction, emissions reduction, and adherence to the waste hierarchy. Since it was introduced, Scotland has introduced ambitious net zero targets and has increased its policy focus on achieving a circular economy. Compared to when the UK-wide Landfill Tax was first introduced in 1996, there is now more emphasis on reducing environmental impacts associated with upstream material use, rather than solely reducing emissions and hazards once materials are in landfill.

This research finds that the lower rate is no longer fully aligned with Scotland’s environmental objectives. Evidence suggests that progress in diverting lower-rate materials may have stalled, with data indicating a levelling-off of lower-rate landfill tonnages since 2020–21 (Figure 1). In addition, there is insufficient incentive to divert materials upstream, including via the planning and design stages of the construction projects which generate much of these materials.

Misalignment with policy goals

While the SLfT was intended to discourage landfill disposal and promote alternative waste management options, the lower rate has, in some cases, created unintended incentives:

• Mechanically-treated fines have become a dominant lower-rate waste stream despite their potential for reduction and recovery, indicating that the tax structure may not sufficiently encourage more circular treatment of the mixed construction materials that make up this waste stream.
• The low cost of landfill disposal creates limited incentives for repurposing soils and stones, which could otherwise be reused in construction and landscaping.
• The lower rate of tax, at £4.05 per tonne (2025-26) appears to have had a limited impact in shifting waste up the hierarchy, with landfill remaining the most economically viable option for many waste producers.

Environmental and economic consequences

Mechanically-treated fines, which now make up a significant portion of lower-rate landfill disposal, have disproportionately high environmental impacts (on a whole life-cycle basis) compared to other lower-rate materials, including contributions to air pollution, resource depletion, and biodiversity loss.

The financial attractiveness of landfill compared to investment in secondary material recovery remains a major barrier. The cost of processing and diverting lower-rate materials often exceeds landfill costs, discouraging investment in alternative waste management solutions.

Compliance and enforcement challenges

The widening tax differential between standard- and lower-rate waste contributes to increased misclassification, particularly for mechanically-treated fines, where interviewees pointed to the ‘production’ of fines in order to qualify for the lower rate.

Landfill operators, who bear the primary tax liability for misclassified waste, face increased financial and compliance risks, leading some to refuse lower-rate fines due to the high burden of tax assessments and retrospective penalties.

Complexities in aligning SLfT qualifying criteria with EWC codes contribute to misclassification, due to a lack of clear guidance for waste producers and operators.

Conclusion and policy implications

The lower-rate SLfT remains partially effective but is increasingly misaligned with Scotland’s circular economy and wider environmental objectives. While it has supported landfill diversion in some cases, the increasing quantity of mechanically-treated fines being landfilled at lower rate undermines resource efficiency and waste hierarchy goals. Without adjustments, in conjunction with other supporting policies, there is a risk that the tax may continue to favour landfill disposal over resource recovery, limiting Scotland’s progress toward a low-carbon, circular economy.

To ensure Scotland meets its waste reduction, emissions reduction, and circular economy goals, reforms to the lower-rate SLfT are necessary. Key areas for further exploration could include:

• Raising the lower SLfT rate by a greater margin than in previous years (as Wales is doing and proposed in the UK’s 2025 consultation), to incentivise application of the waste hierarchy.
• Assigning a significantly higher SLfT rate to mechanically-treated fines specifically, to address misclassification and recognise its relatively high environmental impacts.
• Strengthening enforcement and guidance on material classification to reduce compliance risks.
• Build on existing cross-border regulatory and enforcement cooperation to address ongoing challenges such as waste tourism and the evolution of the landfill tax, recognising the complexities of working across different regimes.

By considering these targeted interventions, Scotland can help reduce reliance on landfill, improve material efficiency, and ensure that landfill tax policy aligns with long-term sustainability goals.

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Appendices

1. Alignment of the Scottish Landfill Tax (SLfT) with broader policy frameworks