Scotland’s construction industry relies heavily on traditional primary aggregates. Lower carbon alternatives such as recycled concrete and incineration bottom ash aggregates are gaining traction. Innovations in recycling technology have improved the feasible quality and consistency of alternatives to primary aggregates, leading to greater acceptance among contractors and suppliers.  

This study sought to investigate the availability of alternatives to primary aggregates and analyse barriers to their uptake through literature review, data collection and stakeholder engagement.

The report provides four case studies of where alternatives to primary aggregates have been used in Scotland. 

Summary of findings

The study has found that alternatives to primary aggregates can reduce greenhouse gas emissions significantly, with local sourcing further amplifying these benefits.

However, logistical and supply chain challenges may limit these benefits when transportation distances exceed certain thresholds. As such, while there are promising pathways for the increased use of alternatives to primary aggregates in Scotland, strategic actions would be required to address existing barriers and to support the transition towards a more sustainable construction sector. 

The three key interrelated challenges to facilitating increased deployment of alternatives to primary aggregates in Scotland are:

• technical viability and infrastructure
• standards and market demand
• data availability. 

In the context of the Scottish Aggregates Tax and other potential fiscal initiatives, there are two headline takeaways from this work: 

• Until robust and reliable Scotland-specific data on volumes of alternatives to primary aggregates is collected, any perceived benefits of tax rate changes will be somewhat speculative. 

• Potential subsidies for alternatives to primary aggregates are considered here at high level. Further work would be required to conduct a thorough assessment of the viability of any such scheme, which would, again, necessitate much more complete data than is currently available. 

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. 

Image credit: Pixabay

Research completed February 2025

DOI: http://dx.doi.org/10.7488/era/5887

Executive summary

Aims

Scotland’s construction industry relies heavily on traditional primary aggregates. Lower carbon alternatives such as recycled concrete and incineration bottom ash aggregates are gaining traction. Innovations in recycling technology have improved the feasible quality and consistency of alternatives to primary aggregates, leading to greater acceptance among contractors and suppliers.

This study seeks to investigate the availability of alternatives to primary aggregates and analyse barriers to their uptake through literature review, data collection and stakeholder engagement. We also provide four case studies of where alternatives to primary aggregates have been used in Scotland.

Findings

We have found that alternatives to primary aggregates can reduce greenhouse gas emissions significantly, with local sourcing further amplifying these benefits. However, logistical and supply chain challenges may limit these benefits when transportation distances exceed certain thresholds. As such, while there are promising pathways for the increased use of alternatives to primary aggregates in Scotland, strategic actions would be required to address existing barriers and to support the transition towards a more sustainable construction sector.

There are three key interrelated challenges to facilitating increased deployment of alternatives to primary aggregates in Scotland. These are technical viability and infrastructure, standards and market demand, and data availability.

• Technical viability and infrastructure: Technical viability of alternatives to primary aggregates is improving. Investment in construction and demolition waste (CDW) infrastructure in Scotland has led to improvements in the purity and quality of alternatives to primary aggregates over the last 10 years. Advanced CDW recycling facilities are prevalent across the central belt, but their reach is limited in rural areas due to logistical and operational challenges, limiting uptake in these regions. Similar to the primary aggregates market, the market for alternatives is characterised by low profit margins, with producers of alternative aggregates also facing high investment costs for the development and expansion of recycling infrastructure. Stakeholders proposed incentivising recycling of recovered flat glass from construction and demolition projects through collaboration with the Scottish food and drink sector.
• Standards and market demand: Some stakeholders suggested updating procurement specifications and regulations to reflect the advances in recycling technology noted above. Broader use of alternatives to primary aggregates is restricted by industry standards and related concerns regarding structural performance. Clients are generally risk-averse and influenced by uncertainties in technical performance quality. This limits market demand. Demand for alternatives to primary aggregates is also limited by competition from traditional materials.
• Data availability: Although aspired to in this study, it was not possible to meaningfully forecast the availability of alternatives to primary aggregates. Low engagement generated limited responses and did not provide a representative dataset of material availability. Without more consistent and granular data, it is not possible to derive a robust definition of the volumes of materials available. That data is not systematically collected and stored as there is no real regulatory or client-led requirement for it, related to the points above. Evidencing the potential for adequate technical performance is difficult when the existing standards are thought by some to not fully reflect what is possible with modern processing techniques. It is difficult to make the business case for investment in a review and potential revision of standards without understanding the potential scale of environmental and economic impact, which is related to the need for more data.

In the context of the Scottish Aggregates Tax and other potential fiscal initiatives, there are two headline takeaways from this work:

• Until robust and reliable Scotland-specific data on volumes of alternatives to primary aggregates is collected, any perceived benefits of tax rate changes will be somewhat speculative.
• Potential subsidies for alternatives to primary aggregates are considered here at high level. Further work would be required to conduct a thorough assessment of the viability of any such scheme, which would, again, necessitate much more complete data than is currently available.

Further research

We have learned lessons that could inform future research:

• Forecasting the availability of alternatives to primary aggregates in the Scottish construction sector is limited by significant data gaps that prevents meaningful baselining of their use.
• Any future studies should factor in a longer data collection period to improve response rates.
• A technical review of existing standards could be conducted to assess the feasibility of updating the current suite of industry standards to reflect advancements.
• Feasibility studies should assess the expansion of infrastructure to rural regions.

Abbreviations

Table 1: Glossary and abbreviations used during report

Introduction

Study context and aims

The Scottish Government has set the target for Scotland to reach Net Zero carbon emissions by 2045, laid out in the Climate Change (Emissions Reduction Targets) (Scotland) Act 2019 (Scottish Goverment, 2019). To meet this target, they understand that GHG reductions must be made across a number of sectors, including the construction sector, which is widely estimated to generate around half of all of Scotland’s waste (Scottish Government, 2024).

In 2023, the Scottish Government commissioned Circle Economy, an international circular economy research body, to map the flow of materials throughout the Scottish economy. The aim of the work was to identify how circular approaches could generate economic benefits and reduce the environmental impacts of waste and material consumption. Their research, among several recommendations, suggests that adopting circular approaches to construction, such as prioritising the use of alternatives to primary materials and aggregates, has the potential to deliver an 11.5% reduction in Scotland’s emissions (Circle Economy, 2023).

To support this aim, the Scottish Government is considering how the Scottish Aggregate Tax can incentivise the use of alternatives to primary aggregates by imposing a tax on the extraction and use of primary aggregate materials. This comes at an opportune moment, as the Scottish Aggregates Tax is expected to go-live in April 2026, and is set to become the third fully devolved tax in Scotland, after the Land and Buildings Transaction Tax, and the Scottish Landfill Tax. It will replace the existing UK-wide Aggregates Levy in Scotland through charging a tax on the use of aggregate when it becomes subject to commercial exploitation in Scotland and will be administered by Revenue Scotland.

However, the evidence base for the significance of the role that alternatives to primary aggregates can play in reducing the environmental impact of the Scottish construction industry is not currently sufficiently robust. There has been no systemic data collection focussing on supply versus demand for alternatives to primary materials in Scotland, and therefore the full extent of the potential environmental impact is unknown. There is also uncertainty about how much more deployment of alternatives to primary aggregates is possible and what the potential options are to overcome the barriers to this ambition.

This study aims to develop a fuller understanding of the types, development levels, and potential impact of alternatives to primary aggregates, and the barriers to their increased use in Scotland. It focuses primarily on aggregates used within the construction industry, which are understood as granular building materials, primarily comprising of sand, gravel, and crushed stone and rock. They are often produced through the crushing, screening, and extraction processes within quarries, or produced as a by-product from demolition practices. While they play a critical role in construction projects, forming the basis of concrete, asphalt, and other materials, their use is not exclusively limited to this industry.

Our work included a review of available industry and academic literature on the subject, an investigation into the availability of relevant primary quantitative data, and a series of stakeholder engagement interviews and surveys. The combined insights from these activities are summarised in this report and draw learnings for policymakers to consider in the further development of the Scottish Aggregate Tax. The methodology followed is discussed in more detail in Appendix A.

Traditional primary aggregates use

In Great Britain, approximately 250 million tonnes of aggregates are used annually within the construction industry, with an additional 20 million tonnes in Northern Ireland. Scotland plays a vital role in the UK’s aggregate supply chain, both as a significant producer and consumer of materials. In 2022, Scotland produced 21.3 million tonnes of crushed rock, accounting for a substantial share of the UK’s total, alongside 4.5 million tonnes of sand and gravel. Additionally, the country produced 1.2 million tonnes of ready-mixed concrete (around 500,000m³), and 2.5 million tonnes of asphalt. Infrastructure projects dominate Scotland’s construction sector, comprising 22% of output and demonstrating a heavy reliance on aggregates (Mineral Products Association, 2024)

The push for sustainable practices in construction has led to growing interest in viable substitutes for traditional primary aggregates. Historically, primary aggregates, sourced from natural materials like rock, granite, and gravel have dominated the market due to their reliability and robust characteristics. Commonly used in applications such as house building and road development, these virgin materials are often chosen by contractors and developers for their proven durability and performance. However, the environmental costs associated with extracting and processing these carbon-intense materials, including significant GHG emissions and the depletion of finite natural resources, present the need for alternative solutions, some of which are set out below.

Alternatives to primary aggregates in Scotland

In 2021, recycled and secondary sources supplied 28% of total aggregate demand, while the remaining demand was fed from primary aggregate extraction in the UK (Mineral Products Association, 2022).

While there is no definitive categorisation of the different materials which may be classed as ‘alternatives to primary aggregates’, in this project we apply the following broad understanding:

• Recycled aggregate: Construction and demolition waste (CDW) that has been processed into usable aggregate.
• Secondary aggregate: Materials derived from the process of extracting aggregate or other industrial processes.

The availability of alternatives to primary aggregates plays a critical role in the successful uptake of sustainable materials in the construction sector. Through desk-based research and stakeholder engagement, it was found that there are a range of suppliers actively producing alternatives to primary aggregates in Scotland. The most commonly produced alternatives were found to be:

• Recycled concrete (RC) and washed recycled sand, which are primarily used in building and housing construction applications
• Incineration bottom ash aggregate (IBA), and
• Recycled asphalt plannings which are typically deployed into road construction and infrastructure developments.

Case Studies

Provided alongside this report are four case studies of project examples where alternatives to primary aggregates have been used in Scotland. These are:

• Case Study 1 – Using alternatives to primary aggregates to extend full fibre broadband across Scotland.
• Case Study 2 – Incinerator Bottom Ash in low-carbon concrete for housing development​.
• Case Study 3 – Treatment of hazardous soil and use of by-products for secondary aggregates.
• Case Study 4 – Sustainable development of the haul road to the East Capellie Recycling Wash Plant.

These case studies demonstrate some of the technical innovations and viability points discussed in Sections 3.1 and 3.3. They also highlight some of the outstanding challenges to stimulating wider replication of the examples discussed, such as a lack of publicly available externally verified full environmental impact calculations, and the lack of firm data on available volumes of the alternative materials discussed. These challenges, among others, are discussed in detail in Section 3.4.

Findings

In this section we present the combined outputs and insights from our literature review, stakeholder engagement, and data collection exercises, organised into general learning themes. Examples of how the themes explored here can impact specific businesses are illustrated in within the Case Studies referenced in section 3.4.

Factors driving uptake of alternatives to primary aggregates

During our stakeholder engagement, representatives of Scottish wash plants and producers of construction materials reported that attitudes to alternatives to primary aggregates have changed significantly over the last ten years. While all stakeholders agreed that there will always be demand for primary aggregates, recent innovations demonstrate that alternatives can now be used effectively in more cases than were previously possible.

Factors driving uptake of alternatives to primary aggregates, as discussed in our interviews, include technical innovations and changing attitudes, explored below.

Technical Innovations

There has been significant investment in development of advanced CDW recycling infrastructure across the central belt of Scotland over the last 10-15 years. Interviewees cited an increase in the number of CDW recycling sites equipped with wash plants, multiple crushers and screening technologies which allow for the removal of contaminants and impurities that can negatively impact the strength of concrete produced from recycled aggregates. This is an advancement on mobile crushing plants traditionally used for the management of CDW, which typically involve single crushing and minimal equipment for the removal of unintended constituents (Pacheco & Brito, 2021). Interviewees felt that these innovations have led to a significant increase in the quality and consistency of the recycled aggregates that can be produced. This view was supported in the interviews by a manufacturer of primary aggregates, a quarry and three operators of CDW recycling and wash plants. Examples of the improved technology are discussed in Case Study 4, provided alongside this report.

When producing concrete, key manufacturers, wash plants and major contractors, are now able to benchmark performance, and grade- and cube test alternatives to primary aggregate. The introduction of these new technologies allows them to understand the compressive strength, relative density and overall quality. Concrete cube testing is an essential process for assessing whether a product meets necessary safety standards and regulatory requirements, and whether they are suitable for different applications within construction. As a result of innovations in wash plant, screening and recycling technologies, these stakeholders are able to produce concrete from alternatives to primary aggregates that are able to meet similar standards and specifications to primary aggregates. This expands the scope of where these materials can be applied.

Changing attitudes

It is acknowledged that the development of Net Zero infrastructure and renewable energy projects, will require a significant increase in concrete production. For some stakeholders, this represented a potential opportunity for greater use of recycled and secondary aggregates. While the rapid growth of renewable energy infrastructure has the potential to reduce overall CO₂ emissions, research has indicated that the increased demand for high impact materials, such as steel and concrete which both have significant carbon footprints, may undermine the environmental benefits of this infrastructure unless otherwise mitigated (Rueda-Bayona, et al., 2022). An interviewed manufacturer of primary aggregates and construction materials noted that they expect this to expand the portfolio of projects where alternatives to primary aggregates may be applied, provided that sufficient quality assurance and standards are in place. They noted that where they had the assets and the capability to supply alternative aggregates, these were being used in nearly every case due to demand from clients motivated by Net Zero targets, such as Tier 1 infrastructure contractors^[1], Local Authority or residential clients.

Interviewees also noted that attitudes have been shaped by the negative impacts COVID-19 and Brexit had on the supply of construction materials. Following the easing of lockdown in 2022, construction projects and demand for construction materials surged. These events created scarcity in the availability of construction materials, particularly cement, leading to fluctuations in prices and long lead-in times for primary aggregates. Due to significant shortage of construction materials and significant lead-in times and costs associated with procuring these materials, Tier 1 infrastructure and housebuilding projects looked to recycled/recovered construction materials to fill the gap. Practical experience with recycled aggregates helped to dispel concerns regarding the quality and practical application of recycled materials.

Environmental impact

The construction sector is the world’s largest consumer of raw materials. According to UNEP and the World Research Institute, buildings account for 40% of all waste generated by volume, 40% material resource use by volume and between 33-37% of all GHG emissions (World Resources Institute, 2016) (UNEP, 2023). In addition, the extraction of primary aggregates, such as rock, sand and gravel generate significant environmental impacts on local biodiversity and habitats. Open-pit mining necessitates the removal of topsoil and vegetation to access the materials that lie beneath. In the UK, up to 22% of sand and gravel is extracted from marine dredging (Mineral Products Association, n.d.). Whilst controlled and responsible marine aggregate extraction would always seek to minimise adverse impacts, there is widely accepted potential for harm to marine habitats from aggregate extraction (United Nations Environment Programme Finance Initiative, 2022). Both activities generate severe negative impacts on animal and plant species and can contribute to sedimentation and erosion of riverbanks and coastlines (UKGBC, 2025).

There is a growing body of evidence that alternatives to primary aggregates can deliver improved environmental performance compared to traditional materials, particularly offering a lower carbon output. Through a rapid review of the literature, we found evidence on lower emissions associated with carbon-reinforced RC industrial flooring (Luthin, et al., 2023), recycled aggregate concrete (Hasheminezhad, et al., 2024) and concrete mixes (Adesina, 2020).

In a study carried out by Luthin (2023), the sustainability performance of a carbon-reinforced RC industrial floor was measured and assessed during its development using the Material Circularity Indicator (MCI) and Life Cycle Assessment (LCA) methods. These tools were used to evaluate both recycled and virgin materials, respectively. Linear resource flows refer to the traditional approach of resource use, where materials are extracted, used, and then discarded as waste, with minimal or no reuse properties. In contrast, circular resource flows aim to extend the lifecycle of materials by prioritising, reuse, recovery, and recycling, reducing the need for virgin material extraction and waste generation.

The study carried out by Luthin (2023) investigated and analysed the recyclability of a floor that that was produced with an RC mixture as the foundation material for an industrial floor, this was then measured and evaluated upon its strength, performance, and carbon profile. The LCA showed that the reinforced RC industrial floor outperformed traditional concrete in environmental performance, achieving a lower Global Warming Potential (GWP). It was shown that the GWP for producing 1 tonne of RC flooring had an equivalent of 80.3 kg CO₂, compared to 195 kg CO₂ equivalent for 1 tonne of precast slabs (Luthin, et al., 2023).

Additionally, the MCI assessment found that the circular performance reflected a similar result, with the reinforced RC floor accounting for a notably high MCI score of 0.8184 (82%) (with a score of 0 being completely linear, and 1 being completely circular). This score reflects the significant use of recycled materials in its production and the potential for further recycling at the end of its lifecycle. In comparison, a new concrete floor composed entirely of virgin materials would score close to 0 on the MCI scale, as it would rely entirely on linear resource flows, using new raw materials with little to no recycling or reuse involved. The MCI score of 82% demonstrates how effectively the RC floor minimises the use of virgin resources and maximises the use of alternatives. Results like this, however, should be read in conjunction with other aspects of the compared materials. For example, this study also found that the RC floor would be more expensive to install, and has higher levels of human toxicity than the precast slab option. This highlights that all material choices should be made based on as full a consideration of all factors as possible.

This assessment is supported by Hasheminezhad (2024) who conducted a similar study, reviewing the LCA and environmental performance of RC in comparison to traditional concrete materials. The study aimed to assess and highlight the GHG emissions and energy consumption associated with the entire lifecycle of concrete resources. This included evaluating the impacts across all phases of its use, including material extraction, production, transportation, usage, and end-of-life management (Hasheminezhad, et al., 2024). The study found that recycled aggregate mixtures of concrete do require marginally higher quantities of energy and cement than primary aggregates. This is often required to compensate for the lower strength and higher water consumption of the recycled materials involved. However, the research underlined the substantial environmental benefits of using recycled aggregate mixtures due to lower carbon emissions, especially when the recycled aggregates are sourced locally. This is due to the use of recycled materials significantly reducing the demand for virgin resources, such as natural sand and gravel, while also diverting CDW from landfills, both of which produce significant associated GHG emissions.

The Hasheminezhad et al. (2024) study also highlighted the GWP differences between the two concrete materials, showing that the GWP of RC was lower by up to 15% compared to natural aggregates, particularly when recycled aggregates completely replaced all natural components within the concrete mix. The whole life assessment outlines the importance and influence of energy consumption generated through extraction and transportation practices. With a particular focus on the value-chain of the resource and the importance of locally sourced materials, embodied emissions are a critical factor when assessing the carbon reduction potential of alternative materials. Embodied emissions relate to the GHG emissions associated with a product or material across its entire life-cycle, including sourcing and processing of the materials, and eventual end-of-life treatment. Therefore, these comparisons should factor all impacts associated with extraction, use and disposal.

The importance of reducing emissions in the transportation of aggregates is also highlighted in a review by Adesina (2020). The report recognises the potential for all aggregates to improve their carbon impact, and the major role in emissions profiles of cement content levels. They also note that the construction industry has made steady and effective progress in reducing emissions throughout the lifecycle of concrete mixtures by prioritising the extraction and efficient use of locally sourced aggregates. By adopting a more strategic approach to the processing and transportation of recycled aggregates, the industry can continue to effectively address and mitigate the challenge of high embodied carbon emissions (Adesina, 2020). This potential was emphasised by several of the stakeholder interviewees for this study as an important contributor to Scotland’s overall environmental ambitions.

It is also important to consider the environmental impacts generated through the transport of primary and alternative aggregates from their point of extraction or production to their point of use. As discussed in sections 3.1.1 and 3.4.4, wash plants for the recycling aggregates are heavily concentrated in the central belt of Scotland. Therefore, the logistical feasibility of supplying recycled or alternative aggregates is limited by distance, as after a certain distance, it becomes uneconomical to supply these materials via truck due to transportation costs. Similarly, after a certain distance, the environmental benefits of alternatives to primary aggregates are outweighed by the emissions generated through transport.

The outcome of an LCA assessment of CDW recycling completed by Ricardo in 2021 for Natural Resources Wales^[2] found that delivery distances of more than 34km from originating site resulted in higher GHG emissions than were saved from the substitution of virgin materials. This break-even distance will increase as transport is gradually electrified and the electricity grid becomes less carbon intensive. This underlines the point that thorough LCA analysis is the only way to accurately reflect the environmental impacts, positive or negative, of any business decision.

Technical viability

Academic discussion

As discussed in the challenges section 3.4 below, there is a widely held perception that recycled or secondary materials can struggle to meet performance requirement standards. Whilst this will clearly be true for some materials, it is not the case for all, and it is important to be able to demonstrate successful use with technical data (Dhemaied, et al., 2024). There is a body of research which focusses on strength, durability, and workability of CDW-derived aggregates in infrastructure projects, with many studies showing promising results for specific applications. Examples are discussed below and in the case studies provided alongside this report.

Recycled sand can replace natural sand in certain construction contexts without compromising quality. In the Virgin Media O2 project under Scotland’s Full Fibre Charter (Scottish Government, 2022b), sand aggregate derived from CDW was successfully used in telecommunications infrastructure, highlighting the role recycled sand can play in sustainable resource management. Case Study 1 provides more information on this example.

Alternatives to primary aggregates have shown strong potential in asphalt applications, particularly for road construction. The UK’s first carbon-neutral road improvement project employed recycled asphalt aggregate to reduce its carbon footprint significantly (Scottish Construction Now, 2021). Additionally, Tarmac’s biogenic asphalt deployed in this project uses plant-based binders with recycled aggregate to achieve effective carbon capture, reducing reliance on petroleum-based materials. This innovative approach demonstrates the potential for CDW aggregates to maintain or enhance the mechanical properties needed for asphalt in road applications, supporting a low-carbon, sustainable future for Scottish road infrastructure (Tarmac, 2023).

RC is a sustainable construction material, primarily produced as a by-product from construction and demolition activities. It is composed of crushed concrete from structured components such as buildings, roads, and pavements, which is then sorted, cleaned and crushed into aggregate (typically between 2-4mm in diameter). Several studies, as discussed below, confirm the technical feasibility of using CDW-derived aggregates in low-carbon concrete formulations, meeting performance criteria for infrastructure applications while promoting sustainability. According to a review conducted by Han et al. (2023), suitably treated RC can act as a sufficient alternative for virgin concrete materials, with strategic adaptations to mortar content and density in recycled aggregates presenting durability and mechanical benefits to the material. This review highlighted that pre-treatment processes, such as the combined usage of lime soaking and carbonation^[3], can also improve the performance and properties of RC within construction. This is both supported and tempered by Thomas et al. (2018), who conducted a performance analysis review measuring the technical feasibility of RC, covering parameters such as the strength and permeability of concrete mixed with recycled materials. The review found that while recycled aggregates show great potential in being a suitable alternative to virgin materials, the strength can be compromised should RC aggregate content exceed 25% of the overall material. However, the review explains that this can be adapted through modifications in the concrete mix design phase, which would be necessary to address changes in the material’s physical and mechanical properties.

Stakeholder opinion

Amongst the stakeholders interviewed for this study, there was broad agreement that the use of alternatives to primary aggregates has been limited due to concerns among construction companies and potential customers regarding quality and consistency in supply of the materials. It was felt that prior experiences, where the quality of materials used had not delivered the required final functionality, have led to clients being wary and sceptical of specifying for anything other than primary aggregates.

Discussion of the current and future situation, however, revealed a mix of viewpoints. There were several reiterations of the opinion that, beyond uses such as landscaping and backfill of drainage and cable trenches, virgin stone will always be preferable to clients. On the other hand, one producer of both primary and recycled aggregates felt that there has been more market acceptance of recycled products over the last four years. As discussed in section 3.1, this has been driven through the normalisation of alternatives to primary aggregates seen during the COVID-19 pandemic and resulting supply chain difficulties, alongside growing recognition of the fact that modern wash plants can produce very high purity output materials. One producer gave an example of a road construction project on their own site, using entirely recycled materials, which has seen 15,000 truck-loads, conveying 0.5M tonnes of materials, without any quality issues (please see Case Study 4 for more detail). This supports the summarised views from the literature discussed above. While there will continue to be the possibility for impurities and deleterious material to be present in alternatives to primary aggregates, it is not correct to assume this is always the case. It was felt amongst some stakeholders that, were robust testing and certification procedures in place to demonstrate how alternative materials comply with industry quality standards, there would be more comfort in their use for a wider range of applications.

These technical considerations, alongside potential environmental and economic benefits, play a critical role in shaping perceptions. Early involvement of client and design stakeholders in planning and decision-making processes is crucial for addressing specific concerns about the material’s use, while effective communication strategies are essential for securing support from both public and private sector clients and project sponsors.

Challenges and barriers to the increased uptake of secondary and alternative aggregates

As part of the movement to incentivise the development of sustainable practices within the construction sector, the broader adoption of non-virgin materials relies not only on their availability and relative demand, but also overcoming several barriers and challenges within the industry. The challenges identified through this study, and highlighted in the separately provided case studies, are categorised and discussed below, along with some initial ideas for options to begin tackling them.

Data challenges

The most significant barrier to developing a full understanding of what is both possible and practical is the lack of availability of robust quantitative data on alternatives to primary aggregates in Scotland. One of the initial ambitions of this project was to forecast the potential contribution to GHG reduction targets of an increase in use of recycled or secondary aggregates in the Scottish construction sector. To calculate this, primary data was sought from key producers and sources of alternatives to primary aggregates in Scotland, including established quarries, wash plants and demolition and excavation companies. The aim was to gain a baseline of annual sales in Scotland. This collated dataset would form a baseline of the potential supply of alternatives to primary aggregates, which would then be mapped against expected demand forecasts, both geographically and volumetrically, to calculate a proportion of how much forecast demand could be met. To calculate the GHG emissions associated with these volumes of secondary and recycled materials, we planned to apply GHG emission factors sourced from various standard approaches.

During the data collection phase, a simplified data collection form was sent to 36 suppliers of primary, and alternatives to primary, aggregates and demolition and excavation companies to request data on the types and volumes of materials sold annually. The research team conducted three rounds of emails and two follow-up calls to each identified supplier over a two-month period to request their participation in the study. Engagement with industry stakeholders was supported by ClimateXChange and members of the Scottish Aggregate Tax Bill Advisory Group (SATBAG).

Despite a large number of suppliers being contacted, the research team received minimal complete responses. There were several reasons for this, including:

• Contacted suppliers had limited capacity to provide the requested data due to resourcing constraints or competing deadlines.
• Contacted suppliers were concerned about potential commercial sensitivity in sharing the data.
• Contacted suppliers did not see the commercial value in participating in the study, despite the relevance of the Scottish Aggregate Tax.

As a result, the limited primary data collected would not have been representative or robust enough to form a baseline for forecasting the future supply potential of alternatives to primary aggregates. Therefore, in agreement with ClimateXChange and the Scottish Government, the efforts to develop a GHG reduction forecast were discontinued and replaced by a focus on stakeholder interviews.

The challenge, and importance, of data availability regarding volumes of recycled and alternative aggregates was reiterated throughout our stakeholder interview phase. This interview phase incorporated four suppliers of recycled and alternative aggregate products contacted during the data collection, and seven public sector, industry and regulatory bodies. The purpose of these interviews was to gain in-depth insights into the key challenges facing the uptake of recycled and secondary aggregates (see Appendix A for further details).

During these interviews, it was noted that data availability inhibits the sector’s ability to forecast the potential environmental benefits of incentivising these alternative aggregates. It also limits understanding of what is possible and practical to aim for when considering the question of supply versus demand. There was a general consensus across the stakeholders interviewed that understanding the volumes available in the secondary market is key, but that such understanding does not currently exist at a sufficient level of accuracy. The difficulty was highlighted as particularly prevalent in Scotland, where interviewees noted suppliers are not used to being surveyed annually. While it is understood that the British Geological Survey is conducted every four years (e.g., in 2019 and 2023), the granularity of detail regarding the origin and characterisation of primary, recycled and alternative aggregates is not particularly well-defined.

To address this challenge, a systematic and robust data collection and reporting mechanism would enable confident, evidence-based decision making, both for Government and for industry members. Ideally, it should provide sufficient granularity to develop a quantitative local authority-level understanding on CDW arisings and volumes of alternatives to primary aggregates produced, stored and sold. Such a system would be complex and expensive to design and implement. The possibility of successful deployment would be maximised through collaborative public-private development.

Potential limited scope for increased use of alternatives to primary aggregates.

In contrast with the potential positive environmental impact and technical viability of alternatives to primary aggregates, is the belief of some stakeholders that there is minimal scope for a significant increase in their use. The potential for increased use of alternatives to primary aggregates needs to be balanced between what is possible and what is practical. The Mineral Products Association’s report, Aggregates demand and supply in Great Britain: Scenarios for 2035 (2022), posits that recycled and secondary aggregates are unlikely to meet projected demand in alignment with construction trends. This is due to the bulk of their supply being directly tied to demolition activity, and the fact that most suitable CDW is already being reused.

This sentiment was backed up in some of our interview conversations with sector bodies. They asserted that, in their estimation, 90% of recoverable CDW is diverted from landfill already and therefore opportunities for significant increases in recycled content are limited beyond incremental improvements. Indeed, the point was made by several interviewees that no-one in any industry likes unnecessary cost and waste, so for many years materials have been reused or repurposed on-site where possible to save costs. As such, construction sites have been adopting the principles of circularity without necessarily reporting it as such. Counter to this, among other stakeholders interviewed with experience in recycled aggregate production, and CDW management in general, there was the opinion that there is still potential for an increase in CDW diversion from landfill. One interviewee confirmed from direct experience that they could easily divert a lot more CDW from landfill and that they have the latent site capacity to process it into recycled aggregate. The only reason this is not done at present is that market demand is not sufficient to warrant the additional processing cost. Another interviewee noted that they have been able to significantly increase capacity since opening their first wash plant in 2017. In this time, they have developed facilities able to handle a much dirtier feedstock and process up to 300,000 tonnes per year at a rate of 150 tonnes an hour.

Addressing the data challenges discussed in Section 3.4.1 should provide clarity on how much scope there is for increased use of alternatives to primary aggregates. If there is found to be additional capacity, then efforts could be made to stimulate demand. These could include championing the role of alternatives to primary aggregates in meeting Net Zero targets through building or collating an evidence base of verified LCA studies or reports which demonstrate positive environmental impact when deployed appropriately.

Another significant opportunity to incentivise the use of alternatives to primary aggregates is through leading-by-example. Through public-sector procurement of relevant projects, mandates and design briefs could be developed to stipulate for, or give appreciable scoring consideration to, the use of alternatives where safe and technically appropriate to do so. The re-released Net Zero Public Sector Buildings Standard (2023) provides an example of how an initiative like this could be developed. While it does provide an embodied carbon (i.e. the emissions embodied in the materials used and construction activities themselves) target for new buildings, it is voluntary and does not stipulate specific measures or materials (Scottish Government, 2023). Opportunities to work within this existing framework, or via other public procurement or planning routes, could be explored and developed.

Challenges due to industry standards

A key factor limiting the uptake of recycled and alternative aggregates was found to be restrictions imposed by industry standards, which are then cascaded into procurement specifications. These established standards are instated to ensure safety, durability, and performance. These standards are designed to regulate the properties and quality of both natural and recycled aggregates across various applications. Key standards are listed in Table 2Error! Reference source not found., below.

Table 2: Key standards relevant to recycled and natural aggregates

It is important to note that these standards have been developed to ensure the structural integrity, durability and safety of built infrastructure. Any increases to these thresholds must be evidence-based, appropriate for the product’s application, and supported by industry-wide consultation. These limits have been established due to well-grounded concerns regarding the potential of deleterious and contaminant materials making their way into recycled feedstock, which may compromise the safety of the structures. In addition, it was broadly acknowledged by all stakeholders interviewed that while recycled and secondary aggregates have many good properties, they will not fully replace demand for virgin aggregates, which will still be required for some applications. Nonetheless, there was concern among producers of recycled and secondary aggregates that existing standards and testing regimes no longer reflect the potential quality and performance characteristics of alternative aggregates produced through modern recycling techniques. While industry standards for the use of aggregates set an upper threshold of 30% of recycled content rate within concrete, some stakeholders reported confidence in the potential of increasing this upper limit without compromising the structural integrity of the concrete produced. If a concrete product contains a recycled aggregate content higher than this threshold, they can only be sold as an unspecified product and as such will not meet procurement specifications.

The feeling from interviewed producers of both primary and recycled or secondary aggregates is that these limitations may restrict market demand. This issue is compounded by the fact that, largely, project specifications require aggregates to meet specific quality and industry standards for which it is difficult for recycled and secondary aggregates, and secondary aggregate containing products such as RC, to demonstrate full compliance. It was noted during the interviews that a lack of relevant standards reflecting current industry practice for alternatives to primary aggregates may contribute to concerns around potential liability if a fault occurs following completion of a project. As a result, engineers and planners may be less inclined to approve these materials for use, and contractors and procurers may not integrate these materials into contracts and structural drawings. Nonetheless, while there was broad agreement that under the current suite of industry standards it is not possible to accurately test the suitability of non-primary material for some structural works, standards and testing regimes do exist to assess the suitability of these materials for non-structural works, such as pipe-bedding, cable laying and landscaping works.

Moreover, stakeholders noted that alternatives to primary aggregates are often not explicitly included within procurement specifications for public or private construction projects. This has the effect of limiting market demand. It is possibly due to a lack of appropriate standards and testing regimes to discern between high-quality and low-quality alternatives to primary aggregates, which for some stakeholders may contribute to misconceptions regarding the perceived risk of using recycled aggregates. In some cases, it was noted that if procurement specifications require a certain percentage of “recycled content” to be used, contractors may feel more comfortable fulfilling this requirement with lower-impact materials used for furnishings (e.g. wood, polypropylene, vinyl flooring), rather than with aggregates, which may deliver greater reductions in GHG emissions.

Almost all stakeholders agreed that the experience of having low-quality recycled aggregate on the market has contributed to misconceptions regarding the purity and performance achievable through innovative modern technological processing techniques. However, significant investment has recently gone into development of quality control processes and technologies to remove contaminants and increase the purity, and therefore quality, of outputs. This improvement and development has thereby expanded their potential uses for other applications.

For example, an operator of a wash plant noted that traditionally contractors used mobile crushers to produce recycled and secondary aggregates from construction, demolition and excavation activities. These crushers often used dry screening to filter out contaminants. However, due to Scotland’s wet climate – and, in the case of excavation, the silt and clay material common in Scotland’s geology – the crushed feed material would often become sticky, making it difficult to remove contaminants and ultimately reducing the purity of the output. Modern wash plants, on the other hand, are often equipped with multiple crushers, washing and screening technology to crush and effectively segregate aggregates from these contaminants. In the case of excavation activities, this also allows for the collection of the silt and clay as a valuable by-product. Similarly, an interviewed producer of construction materials noted that clients and contractors may not be aware that this sector is rapidly evolving, and that technologies are coming online that can, for example, extract the cementitious properties of concrete and recover the concrete used.

In conclusion, current standards and specifications for recycled and secondary aggregates are felt by industry stakeholders to be outdated or restrictive, failing to support the technological innovations and resultant industry confidence. As noted above, while demand for recycled and secondary aggregates has traditionally been lower than primary aggregates due to concerns regarding quality and consistency in supply, there is a sentiment among some interviewees that this has changed as a result of research and development investment and innovation, leading to significant improvements in the quality of materials that can be produced from CDW. While the structural integrity of built infrastructure must not be compromised, to enable broader recycled and secondary aggregate adoption, updates to standards and specifications are essential to reflect current practice and provide guidance on the materials’ structural performance.

To address these challenges, there is an opportunity to review current industry standards, to understand if there is scope to develop and update them to better reflect modern recycling capabilities and the quality of alternative aggregate products they can produce. Additionally, as with the option to develop a library of proof of environmental performance discussed in Section 3.4.2, a suite of case studies could be built or collated to demonstrate good practice and the technical appropriateness of alternatives to primary aggregates.

Operational and market challenges

There was broad disagreement among the stakeholders interviewed for this study regarding the need to provide additional support for the uptake of alternatives to primary aggregates. This was due to contrasting views regarding the perceived ‘saturation’ of recycling and wash plants across the central belt of Scotland, the operational barriers of expanding aggregate recycling facilities to rural areas, and the challenges in segregating CDW at source.

It was felt that the saturation of state-of-the-art facilities (e.g. wash plants), combined with a lack of demand for non-primary aggregates for reasons discussed above, means some of these businesses are sitting on significant amounts of washed concrete, recycled sand and gravel, with no off-take market (i.e. customers to buy their product). Indeed, four interviewees noted they could significantly increase their recycled output if there was sufficient market demand to justify it.

Within this context, some stakeholders representing primary aggregate suppliers felt that if the Scottish Government used financial or legislative support such as increasing the tax rate applicable under the Scottish Aggregates Tax to generate market demand and incentivise the use of recycled or alternatives to primary aggregates, the primary aggregate sector would be placed at a competitive disadvantage. These state-of-the-art facilities require millions of pounds of investment, which creates a barrier to entry for primary aggregate suppliers seeking to move into the recycled aggregate market due to sustainability and Net Zero benefits. In addition, these stakeholders felt that as some recycled aggregate companies operate their own fleets, they may be more readily able to drop the price of the recycled aggregates in order to sell excess stock, which may contribute to increased market volatility and reduce the competitiveness of primary aggregates.

On the other hand, producers of recycled- and alternatives to primary aggregates felt that their competitiveness was overstated due to the operational and geographic limitations of their business models. It was noted that traditional quarrying allows significant volumes of primary aggregates to be sourced (e.g. through drilling and blasting) and sent out for delivery with lower overheads and lower investment in infrastructure. This allows them to compete favourably against producers of recycled aggregates that require investment in high-specification wash plants, trash screens, and technology to grade and segregate feedstocks.

In addition, suppliers of alternatives to primary aggregates interviewed noted they were also constrained geographically, as their infrastructure needs to be situated in a catchment area where there is a high volume of CDW being generated. This makes competition with traditional primary aggregate suppliers challenging. This is especially true in rural regions outside of Scotland’s central belt, where it is currently not commercially viable to operate wash plants or supply non-primary aggregates due to a lack of non-primary material inputs, and the haulage and fuel costs associated with transporting these to customers. One interviewee noted the fuel costs may be subject to change, if they were able to transition their fleet to electric vehicles supplied by renewable sources. However, this remains a significant operational barrier.

It was generally agreed by interviewed stakeholders and within the supporting literature, that to maximise the financial and environmental benefits of using alternatives to primary aggregates, these should be used as close to the source as possible (e.g. demolition sites or construction sites) (Wang & al., 2024) (Santolini & al., 2024). However, there was concern that availability of recycled and secondary feedstock was also often constrained by resistance within construction and demolition companies to appropriately segregate materials at source, due to concerns regarding feasibility and costs. There was broad agreement that this was due to the structural and commercial pressures that construction and demolition companies face when delivering a contract. It was explained that demolition contracts tend to be awarded for efficiency and speed to avoid financial penalties for not completing a project within the timeframe set by the agreed upon planning permissions. This can lead to a tendency for operators to make business decisions based on the belief that the removal of specific structural elements and the use of screening technology to facilitate reuse and recycling of aggregates will be time consuming and generate additional, unwanted costs.

One specific example is the lack of on-site removal and screening being a key barrier to the recycling of flat glass. Currently, the Scottish Landfill Tax provides little financial incentive to recycle flat glass recovered from buildings as this material qualifies for the lower rate of landfill tax of £4.05/ tonne from 1 April 2025 (previously £3.30/tonne). As a result, recovered glass is crushed for use as a low-value input for aggregates in road construction or landfilled. British Glass (an industry body representing the UK glass industry) noted this is a significant lost opportunity to maximise the value generated from glass recycling, minimise avoidable waste, and reduce GHG emissions. Glass can be continuously recycled and remelted into new glass products without loss of quality, provided it is appropriately segregated to avoid impurities. Their estimates indicate up to 200,000 tonnes of flat glass is generated by the UK demolition and construction sector. If flat glass was diverted from landfill and remelted into new glass products, this could save 60,000 tonnes of CO₂ per year. Replacing virgin raw materials with 10% recycled glass saves 3% of furnace energy when producing glass products (British Glass, 2024).

While there are currently no flat glass recycling facilities in Scotland, British Glass emphasised that there is significant market demand from the Scottish food and drink manufacturing sector, particularly Scottish whisky and gin distilleries, for recycled glass materials in order to reduce their Scope 1 emissions (those that are directly generated through their operations). As such, they underlined the clear synergies and shared economic benefits of greater cross-sector collaboration for the recovery and segregation of flat glass products (e.g. windows) for recycling by the food and drink sector into glass packaging (e.g. bottles). This would only be feasible if appropriate on-site practices were implemented by stakeholders within the construction and demolition sector.

To mitigate these operational challenges, stakeholders interviewed felt that the costs of the segregation and processing of recovered aggregates and glass could be passed onto the client, especially if this was mandated or supported by legislation. A change in planning permissions or adjustments to the Scottish Landfill Tax that increases the cost of disposal were both suggested as potentially significant levers for change.

Finally, it should be noted that several interviewees reflected the view that wash plants should be seen as complementary to, and not competitive against, the existing producers of primary materials. Through sector collaboration it was perceived that increasing use of alternatives to primary aggregates would contribute to the extension of the useful lifetime of quarries, while producing materials that may not directly compete with materials derived from hard rock quarries, such as clean crushed stone.

The market stimulation efforts and ideas to tackle challenges due to industry standards discussed in the above two sections would go some way to tackling the challenges discussed here as well. To address the issue of alternatives to primary aggregates only really making environment and commercial sense if used relatively closely to where they are produced, effort could be made to support the development of recycling infrastructure in areas away from the already well-served central belt of Scotland.

Fiscal factors

There was broad agreement among stakeholders that, currently, the cost of purchasing alternatives to primary aggregates is comparable to that of primary aggregates. Yet, despite this similarity in pricing, there is a preference for primary aggregates in the market. Our findings indicate this is driven by the quality issue perceptions discussed above and the associated costs and challenges of ensuring compliance with required standards (e.g., screening, sorting, testing). However, there could be two areas of flexibility that could support a shift of this market dynamic in favour of alternatives to primary aggregates.

These are:

• Tax rate adjustments for primary aggregates: The Government could choose to raise the tax rate on primary aggregates to further strengthen the incentive to use alternatives to primary aggregates.
• Subsidies for alternatives to primary aggregates: Businesses that reduce the use of primary aggregates by incorporating alternatives into their operations could be made eligible for a subsidy scheme. Payments could enable businesses to lower their costs and for these cost savings to be passed on to customers. This could lead to more competitive pricing for products made with alternatives compared to those made with primary aggregates.

Tax rate adjustments for primary aggregates

The Scottish Government’s review of evidence and policy options for the Scottish Aggregates Tax (2020b) conducted an illustrative modelling exercise (based on tax rates at the time) for four tax rate scenarios:

• Option 1 – High levy rate (Tax increase scenario): Under this option, the Scottish Aggregates Tax rate is set above the UK levy rate.
• Option 2 – Low levy rate (Tax decrease scenario): Under this option, the Scottish Aggregates Tax rate is set below the UK levy rate.
• Option 3 – Scottish Government baseline (No tax scenario): The levy rate is set to zero under this option, to model the impacts of a ‘do nothing’ approach.
• Option 4 – New landfill tax band for aggregates (Landfill scenario): The levy rate is kept at the same level as the UK levy rate, while creating an additional band of landfill tax for aggregates which is higher than the rate for landfilling inert materials.

The results of this modelling are reproduced in Table 3 below.

Table 3: Modelled tax rates and impacts under different policy scenarios (reproduced from (Scottish Government, 2020b))

Unsurprisingly, the modelled outcomes for raising the tax rate for primary aggregates and for introducing additional costs for landfilling of aggregates (Options 1 and 4 respectively) show a decrease in the use of primary aggregates and an increase in the use of alternatives. These are expected results for the unambiguous financial interventions into the market modelled. However, the level of redistribution of total demand between primary and alternatives aggregates that is actually possible, and the resultant worth of that compared to additional administrative costs, remains unclear. The 2020 Scottish Government review highlights that 87% of CDW is already recycled in Scotland, and the challenges discussed in Sections 3.4.1 and 3.4.2 above corroborate and augment this note of caution. Until robust and reliable Scotland-specific data on volumes of alternatives to primary aggregates is collected, any perceived benefits of tax rate changes will be somewhat speculative.

Subsidies for alternatives to primary aggregates

While alternatives to primary aggregates will be already be exempt from the Scottish Aggregates Tax, there is the potential to further incentivise their use by offering a subsidy. Potential recipients, such as those economic operators placing alternatives to primary aggregates on the market, would need to comply with any systems set up to verify amounts being claimed, so introducing some administrative burden.

The potential impacts and costs of introducing a subsidy system which aims to offer a positive incentive for using alternatives to primary aggregates are impossible to robustly estimate without access to granular volume data. Any potential scheme itself could require claimants to collect, store and report data on alternatives deployed. This potentially could include volumes and rates of CDW reused on site, capturing material which is not currently reflected in standard waste reporting as it never officially becomes waste. While this would incentivise the use of alternative aggregates and avoid the negative associations of disincentivising primary aggregates through the use of a tax increase, it would necessitate increased administrative and resource burden on both the scheme administrator and relevant claimants. Further work would be required to conduct a thorough assessment of the viability of any such scheme, which would, again, necessitate much more complete data than is currently available.

Summary learnings and next steps

The learnings drawn from the evidence review and potential actions for policymakers are summarised below:

• Alignment with net zero targets: The Scottish Aggregates Tax could emphasise the potential role of alternatives to primary materials in meeting net zero targets in the construction sector. This could be relevant for other sectors that may have a use for these materials, such as food and drink manufacturing. This is particularly relevant for the GHG reduction potential of recycled aggregates, as well as for the recycling of flat glass. These environmental benefits can be evidenced through lifecycle assessments, which demonstrate the carbon savings potential of using recycled aggregates and glass.
• Data accessibility and transparency: Significant data gaps exist in the monitoring of CDW generation and resultant availability of materials that could be used as alternatives to primary aggregates. This might complicate the implementation of any potential future Scottish Aggregates Tax rate changes and generate reasoned resistance from affected stakeholders. Robust data on waste arisings generated from CDW projects, and the types, quantities and value of alternatives to primary aggregates produced and sold, would enable policymakers to more accurately monitor and understand market dynamics for these types of materials. Given the resource demands of additional data collection, we suggest that systems and processes would need to be developed collaboratively between government and industry partners to promote engagement and adherence.
• R&D investment: Continued investment in advanced recycling infrastructure can improve the quality of recycled aggregates. Public-funded R&D could support existing recycling facilities and develop recycling capacity among primary aggregate suppliers, particularly in underserved rural areas.
• Addressing quality perceptions: Sector wide misconceptions regarding secondary and recycled materials, often based on historic experience, limit market demand. Public sector and industry partners could seek out targeted opportunities to emphasise successful case studies and promote quality assurance practices.
• Updating standards and specifications: Industry standards restrict the use of alternatives to primary aggregates. Investment in R&D to review and potentially update industry standards could better reflect modern recycling capabilities. This could also contribute to addressing the quality perceptions discussed above. This could be complemented by engagement with standards bodies, such as British Standards, National Highways and Transport Scotland.
• Capacity building and market demand: Policymakers could capitalise on latent capacity for recycling facilities could increase their capacity by implementing mandates and incentives to require and encouraging the use of alternatives to primary aggregates (e.g. in public sector procurement), where safe and technically appropriate to do so.
• Facilitate cross-sector collaboration: Policymakers could support innovation to incentivise cross-sector collaboration for the recovery and recycling of flat glass from construction and demolition projects.

Policymakers should continue to effectively engage with key stakeholder groups within the aggregate industry to ensure any measures, including changes to tax rates and provision of financial incentives, are feasible and accepted. Additionally, the majority of the barriers discussed in this report will require engagement and the development of a mutual understanding with wider stakeholder groups. These include:

• Private sector customers of primary and alternatives to primary aggregates, including Tier 1 contractors, homebuilding contractors, landscapers and relevant trade associations.
• Public sector customers of primary and alternatives to primary aggregates, including local authorities and relevant public sector procurement representatives.
• Relevant industries that may benefit from recycled aggregates, such as the Scottish food and drink sector for the recycling and valorisation of recovered flat glass.
• Relevant industry standards bodies and research institutions to review feasibility of updating existing standards for alternatives to primary aggregates.

In summary, while there is a bank of academic, grey literature and stakeholder-opinion evidence that alternatives to primary aggregates can play a practicable and impactful role in reducing GHG emissions in Scotland, there is not universal agreement in the industry on these points. There are significant challenges and knowledge gaps to overcome. There are questions about the feasibility of increasing the proportion of alternatives to primary aggregates deployed, from both the available supply and market demand angles. There are deeply held reservations about the ability of alternatives to primary aggregates to provide the required technical performance, compounded by a sentiment that industry standards do not accurately reflect current recycling capabilities. Finally, there is a clear lack of robust, granular, Scottish-specific data to provide unequivocal clarity on several of the contested points. This study has detailed the key points of these challenges, their roots, and suggested some potential options to begin tackling them to facilitate a move to a more circular economy and sustainable construction sector in Scotland.

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Appendices

Appendix A: Methodology

In the completion of this report, the research team completed the following activities:

• Task 1: Policy drivers workshop
• Task 2: Literature review
• Task 3: Data collection
• Task 4: Stakeholder interviews

These activities are described in more detail below.

Task 1: Policy Drivers workshop:

Following inception of the project, a workshop was held with representatives of the Scottish Government, CXC, Ricardo and members of the Scottish Aggregates Tax Bill Advisory Group (SATBAG). This workshop was used as springboard to discuss the aims and objectives of this research project, establish a common understanding of:

• The taxation and regulatory context as it pertains to the Scottish Aggregates Tax and Scottish Landfill Tax, including:
• The potential and feasibility of different tax rates to remove barriers to the use of alternatives to primary aggregates.
• Relevant regulations and potential exemptions that might influence their use.
• SEPA’s potential role in providing data and regulatory input into the research.
• Barriers to the use of secondary and alternatives to primary aggregates, including discussion of: market perceptions, commercialisation issues, cost considerations, and relevant regulations.
• Environmental considerations, including: the environmental impact of recycling and potential unintended considerations, alongside policy drivers to minimise waste arising from construction.
• Future research and data need to address potential data gaps and requirements to facilitate survey and evidence gathering.
• Industry engagement to develop a clearer picture of how tax and regulatory changes will affect different parts of the industry, as well as consideration of cross-border traffic of aggregates between Scotland and other areas, which could impact the effectiveness of any tax or regulatory changes.
• Expected impacts and considerations, including price sensitivities to assess the long-term impacts of a policy shift, and the need to carefully balance the economic impact on industries that rely on primary aggregates with the environmental goals of promoting secondary aggregates and minimising waste.

Task 2: Literature review:

An in-depth literature review was undertaken of academic, grey and white paper sources relating to the economic and environmental impacts of the use of alternatives to primary aggregates and their use. The scope of the review primarily focused on Scottish and UK-related studies, and was expanded to cover international best practice studies, particularly as they pertain to life-cycle assessments of alternatives to primary aggregates. These findings were collated in an Excel Document Register to facilitate the identification and analysis of key themes relevant to the study. The sources identified are summarised in Table 4, below.

Task 3: Data collection and analysis:

Following the literature review, the research team progressed to primary data collection from relevant industry stakeholders involved in the supply of alternatives to primary aggregates in Scotland. The purpose of this activity was to gain a baseline understanding of the availability of alternatives to primary aggregates being sold in Scotland. This was then to be used to forecast the potential contribution to GHG reduction targets of an increase in use of recycled or secondary aggregates in the Scottish construction sector. To do this, the research team conducted desk-based research to identify up to 36 suppliers of aggregates, which included: manufacturers of primary aggregates, wash plant operators, construction and demolition waste recyclers, and demolition and excavation companies. Once identified, the collection of primary data was split into two sub-tasks: data collection surveys, and long-form interviews:

Sub-task 3.1: Data collection surveys:

The research team sent out data collection surveys to request the following information for the periods Jan-Dec 2021, Jan-Dec 2022, Jan-Dec 2023:

• Material types supplied
• Manufacturing locations
• Quantities of material produced per year (tonnes)
• Associated standards and quality control measures
• Challenges associated with either collecting or increasing supply of each material type.

Due to data challenges described in section Error! Reference source not found., the research team received insufficient primary data to accurately forecast the potential availability of alternatives to primary aggregates.

Sub-task 3.2: Stakeholder interviews:

The research team conducted 4 interviews with relevant private companies and industry groups, listed in Table 5, for a duration of 45-60 minutes. The purpose of these interviews was to complement the data collection surveys and gather qualitative data to be used in Task 4, described below.

Table 4: Research activities completed

Task 4: Investigate barriers and solutions to the supply of alternatives to primary aggregates:

Following the literature review and data collection phase, the research team conducted a series of interviews with relevant stakeholder groups to discuss any challenges or barriers to the uptake of alternatives to primary aggregates, and to assess potential fiscal or regulatory levers that could be used to mitigate these.

The aim of this phase was to facilitate a deeper understanding of how government and industry can work together to use environmental levies and associated instruments to affect the best possible climate impact and identify any barriers that may negatively impact their implementation. An interview script was developed to gain stakeholder inputs on the following topics:

• Perceptions and attitudes toward alternative materials to primary aggregates
• Operational considerations related to the supplying of alternatives to primary aggregates
• Technical, regulatory and market barriers to the uptake of alternatives to primary aggregates
• The policy and regulatory environment related to the application of alternatives to primary aggregates

To ensure that a broad range of viewpoints were considered, 10 interviews were conducted with relevant stakeholder groups identified from the SATBAG and during stakeholder engagement activities in Task 3. These stakeholders are recorded in Table 5.

Table 5: Stakeholders engaged

Each interview was recorded and the transcript was cleaned and recorded in an Excel matrix to facilitate objective comparison and analysis of each stakeholder group’s perspective on the above noted topic areas.

Task 5: Synthesising results and report writing

Following completion of Tasks 1-4, the research team reviewed all evidence gathered throughout the study to identify key themes, areas of consensus, and areas where evidence or viewpoints may diverge or contradict each other. These were then mapped against the key objectives of the research project and grouped according to theme. This provided the basis of section Error! Reference source not found. in this report. Following this initial review, an interim report was developed and presented to CXC and representatives of the SATBAG to gain their input and ensure all viewpoints are objectively recorded within the body of the report.

Appendix B: Case studies

Provided as a separate document: Appendix B: Case studies – The role of alternatives to primary aggregates in reducing emissions from the construction sector

How to cite this publication:

Rob Snaith, R, Foss, J, Connell, J and Bonfait, J. (2025) The role of alternatives to primary aggregates in reducing emissions from the construction sector, ClimateXChange.

DOI http://dx.doi.org/10.7488/era/5887

© The University of Edinburgh, 2025
Prepared by Ricardo on behalf of ClimateXChange, The University of Edinburgh. All rights reserved.

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

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. 
   

   Large construction companies that generally manage the entire construction process for a project, often employing sub-contractors as part of the project delivery team. ↑

   
   
2. 
   

   Unpublished internal report ↑

   
   
3. 
   

   Saturating in limewater to introduce calcium into the material, thereby augmenting the carbonation reaction in which CO₂ in the atmosphere is diffused into cement-based material to react with CH and form calcium carbonates. Results in enhanced strength and durability. ↑

   
   

The Scottish Government’s Climate Change Plan update recognised the role that emissions removals will need to play in reaching net zero. Direct air capture (DAC) technologies extract CO2 directly from the atmosphere at any location rather than at the point of emissions. CO2 can then either be stored or used for a variety of applications, such as producing more sustainable fuels.  

This study explored the costs and profitability of DAC and conducted an international comparison, through an evidence review, stakeholder engagement and modelling. The researchers modelled the two leading technologies: solid DAC and liquid DAC. 

Findings

• Demand for DAC CO2 in Scotland by 2040 will be approximately 0.1-0.15 Mt, rising to 0.2-0.24 Mt in 2050. This is far below the demand levels needed to make a 0.5 Mt DAC plant profitable.
• Experts highlighted market demand for CO2 as a key limiting factor with the sector currently relying on voluntary carbon markets, which are volatile.
• The cost of DAC is expected to drop by 30%-60% by 2040, depending on the technology.
• By 2040, the cost of solid DAC is projected to be around £560 per tonne of CO2 and that of liquid DAC £340 per tonne of CO2.
• Despite the potential for DAC in Scotland to reach the costs compatible with profitable synthetic sustainable aviation fuel (e-SAF) production, e-SAF from DAC CO2 is still projected to be one of the most expensive forms of e-SAF compared to e-SAF synthesised from other CO2 sources.
• Solid DAC would not be profitable for usage with the projected Emissions Trading Scheme (ETS) price of £142 per tonne of CO2 in 2040, but would require an ETS price of £250-£350 per tonne of CO2.
• Low-carbon electricity from renewable energy (especially wind) is an advantage for Scotland. However, given the higher cost of electricity in the UK, Scotland and wider UK are less attractive locations for DAC than other countries.
• Using green hydrogen for liquid DAC increases costs by 33%.

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.

Research completed March 2025

DOI: http://dx.doi.org/10.7488/era/5940

Executive Summary

Overview

The Scottish Government’s Climate Change Plan update recognised the role that emissions removals will need to play in reaching net zero. Direct air capture (DAC) technologies extract CO₂ directly from the atmosphere at any location rather than at the point of emissions. CO₂ can then either be stored or used for a variety of applications, such as producing more sustainable fuels.

This study explores the costs and profitability of DAC and conducts an international comparison, through an evidence review, stakeholder engagement and modelling. We based the modelling on a 0.5 Mt DAC plant in Scotland operating in 2040, based on a Negative Emissions Technologies study by the Scottish Government. We modelled the two leading technologies, solid DAC and liquid DAC.

Key findings

Our modelling shows that demand for DAC CO₂ in Scotland by 2040 will be approximately 0.1-0.15 Mt, rising to 0.2-0.24 Mt in 2050. This is far below the demand levels needed to make a 0.5 Mt DAC plant profitable. Much of this projected demand is driven by the UK sustainable aviation fuels (SAF) mandate that sets out targets for synthetic aviation fuel (e-SAF) – see figure 1.1. This highlights the importance of government policy for creating a sustainable market. To create demand for a 0.5 Mt DAC plant in Scotland, either Scotland would need to provide a disproportionate amount (~40%) of the UK’s synthetic fuels (particularly e-SAF), DAC would need to supply the vast majority of the CO₂ used to make e-fuels, or much of the captured CO₂ would need to be sent to storage as CO₂ offsets. Please note that in this study, we assumed that only 50% of CO₂ for e-SAF would come from DAC. However, the Committee on Climate Change 7^th Carbon Budget (published after we conducted the study) assumed that all CO₂ required for e-SAF comes from DAC. Therefore, the projected DAC demands for e-fuels are roughly double the values shown here.

Figure 1.1: Projected CO₂ demands for e-SAF until 2050 in the UK (left) and Scotland (right). This demand would be met by a mixture of CO₂ sources, not solely DAC.

Experts highlighted market demand for CO₂ as a key limiting factor with the sector currently relying on voluntary carbon markets, which are volatile. Government policy will be central to setting out a market, or markets, for DAC CO₂ but is not yet fully developed. Planning restrictions, including timelines for approvals, land use concerns and uncertainties around final project specifications, create further hurdles. Other constraints include supply chain bottlenecks, though none of these are viewed as critical, and the immature state of CO₂ transport and storage infrastructure.

The cost of DAC is expected to drop by 30%-60% by 2040, depending on the technology. This will be driven by improved processes and materials, economies of scale and learning by doing. High gas prices in the UK mean that Scotland is not a particularly attractive location for liquid DAC, so advances in solid DAC will most likely be of greatest relevance. Industry experts highlighted the value of learning from current deployments such as understanding the impact of climate conditions, and how carbon capture materials perform and can be produced on an industrial scale. Integration with waste heat could have a significant impact on the cost of solid DAC to below £400/tCO₂. Both the e-fuels and green hydrogen production industries could be expected to grow on a similar timescale to DAC and would be obvious industries to co-locate with DAC due to their production of waste heat.

By 2040, the cost of solid DAC is projected to be around £560/tCO₂ and that of liquid DAC £340/tCO₂. The starting point for the liquid DAC cost ranges are much more uncertain as the technology has fewer deployments than solid DAC. If the UK Government Emission Trading Scheme (ETS) price was set in order to be a penalty for exceeding emission allowances, the cost of DAC plus CO₂ storage could be used effectively to set the ETS price. To be compatible with the e-SAF buyout price set in the UK SAF Mandate, DAC CO₂ would need to cost below £400/tCO₂. Our modelling suggests liquid DAC could reach this cost by 2040. Solid DAC has the potential to reach these costs if the plant has access to low-cost electricity (in the region of 6p/kWh), potentially aided by waste heat from other process such as green hydrogen or e-fuel production.

Despite the potential for DAC in Scotland to reach the costs compatible with profitable e-SAF production, e-SAF from DAC CO₂ is still projected to be one of the most expensive forms of e-SAF compared to e-SAF synthesised from other CO₂ sources. It would also be multiple times more expensive than current aviation fuels. The e-SAF buyout price in the SAF mandate has been set accounting for the cost of DAC CO₂. The analysis in this study indicates that DAC CO₂ would need to be in the region of £400/tCO₂ to be compatible with the buyout price in the SAF mandate. This is compatible with projected liquid DAC costs in 2040 or solid DAC when using a mixture of low-cost electricity and waste heat. The buyout price is set to ensure that it is more economical to buy DAC e-SAF than to not meet the e-SAF mandate requirements. However, if other forms of e-SAF can meet the demand, the market for DAC e-SAF could be much smaller than projected here.

This is amplified when considering DAC as a CO₂ feedstock for shipping e-fuels, where there are more options for decarbonised fuels and current fuel costs are lower than for aviation fuel. Even by 2050, shipping fuels are still projected to be up to 3 times more expensive than current shipping fuels (UMAS, 2023). A key future consideration with shipping e-fuels is whether ammonia comes through as a major fuel, which does not require a carbon feedstock such as DAC. If it does, ammonia could take up a lot of the shipping fuel market. However, significant safety concerns remain. If ammonia’s role is smaller than current projections, then the role of carbon-based e-fuels for shipping and of DAC would be larger.

Solid DAC would not be profitable for usage with the projected ETS price of £142/tCO₂ in 2040, but would require an ETS price of £250-£350 /tCO₂. To make DAC competitive with other sources of CO_2, the ETS price would need to make up the difference between DAC and CO₂ from other sources, currently around £100-£300/tCO₂ depending on the use case and market fluctuations. The ETS scheme is still considering how DAC CO₂ that is re-released is to be treated. DAC CO₂ may not earn credits, but for instance if fuels made from DAC were carbon neutral, that fuel would not use any carbon credits.

Energy prices account for up to 80% of the cost of DAC. Countries or regions with low and stable energy prices, such as Iceland and Texas, are generally more favourable for DAC deployment compared to regions like the UK, where energy costs remain relatively high. The most competitive locations for solid DAC are those with both low-cost and low-carbon electricity, especially when considering the levelised cost of removal (LCOR), as shown in Figure 1.3. The LCOR is the cost of removing 1 tonne of CO₂ from the atmosphere, accounting for any CO₂ released in the process of capturing the CO₂ e.g. CO₂ emissions from energy used for the process.

Low-carbon electricity from renewable energy (especially wind) is an advantage for Scotland. However, given the higher cost of electricity in the UK, Scotland and wider UK are less attractive locations for DAC than other countries with a similar portion of low-carbon energy, as illustrated in Figure 1.3. For liquid DAC, gas prices are a key influence as gas is used to generate the high temperatures needed for the liquid DAC process. However, gas prices in the UK are high, meaning that Scotland is not an attractive location for liquid DAC compared to other international locations.

Figure 1.2: The influence of electricity price on the LCOR of solid DAC across international locations.

Using green hydrogen for liquid DAC increases costs by 33%. These costs are comparable to solid DAC when solid DAC is paired with low-cost electricity or waste heat (i.e. the lower cost solid DAC scenarios).

Abbreviations Table & Glossary

Introduction

This study explores the cost and profitability of direct air capture (DAC) technology in Scotland. The findings from this report will feed into the evidence base for the Scottish Government on DAC technology. The focus of this study is on the capture and utilisation of CO₂, as opposed to CO₂ storage.

Aims

The key aims of this project were to:

• Review the main research and development (R&D) trends in DAC: high activity research areas, the likelihood of success and the impact if successful
• Understand key limiting factors in DAC deployment and scale up
• Provide projections for the likely cost of DAC in Scotland and the key sensitivities
• Understand how various scenarios, such as low-cost electricity and waste heat, would influence DAC costs
• Understand how Scotland compares to other countries as a location for DAC
• Quantify potential markets for DAC, both established and emerging, the size of those markets and potential for profitability.

Overview

The modelling in this study is based on a 0.5 Mt DAC plant, with both solid DAC and liquid DAC studied at this capacity. This 0.5 Mt capacity has come from the Negative Emissions Technologies study by the Scottish Government based on the Storegga and Carbon Engineering project, which was proposed to be built in the late 2020s with assumed minimum capture rate of 0.5 MtCO₂ (Scottish Government, 2023).

The information in this study brings together academic literature with cost modelling alongside insight from interviews with DAC experts in industry and academia. It is important to note that the values in this study are projections based on best available data for a developing technology so are subject to significant uncertainty. Where possible, indications are given as to the main factors impacting the values provided and how changes to some of the assumptions would affect them.

Throughout this study, two key terms are used: levelised cost of DAC (LCOD) and levelised cost of removal (LCOR). The LCOD is the cost of capturing one tonne of CO₂ from the air, quoted in terms of £/tCO₂; the LCOR is the cost of removing one tonne of CO₂ from the atmosphere, accounting for any CO₂ released in the process of capturing the CO₂ e.g. CO₂ emissions from energy used for the process. If zero carbon energy were used, the LCOD and the LCOR would be equal. LCOD is the important metric for comparing DAC costs from a purely economical point of view, however, carbon credits will be assigned based on the carbon removed such that LCOR is still a key economic metric as well being important from a carbon reduction perspective.

Overview of DAC Technology

The carbon capture process

The process of capturing CO₂ directly from the air has three generic phases (Third Derivative, 2021):

• Drawing air containing CO₂ at atmospheric concentration of around 400 ppm into the system and bringing it into contact with a carbon-capture material
• Reaction of CO₂ with the carbon-capture material, usually either a liquid absorbent or a solid adsorbent
• Releasing the CO₂ from the capture material to be used or stored, and regenerating the capture material to begin the cycle again

DAC technology

DAC technology has two main types: solid DAC and liquid DAC. The solid and liquid refers to the materials that are used to capture the carbon. In liquid DAC, the CO₂ is absorbed into a liquid solution of potassium hydroxide or another base; this is the method used by the DAC plant developer Carbon Engineering, a partner in the planned Acorn DAC facility at Peterhead. In solid DAC, the method used by the businesses Climeworks and Global Thermostat, solid materials are used with the CO₂ adsorbed (binding) to the material surface.

Both processes use heat to release the CO₂ and regenerate the capture material, but liquid DAC needs much higher temperatures to do so, in the region of 900°C compared to solid DAC around 100°C (Sodiq, 2022). The high temperatures needed for liquid DAC means natural gas is currently used as part of the process, with the CO₂ from the gas burned being captured in the process. This is the method used by Carbon Engineering.

More detail is provided on each of these methods in Appendix A.

Research and Development Trends

DAC is an active area of research both in industry and in academia. Academic research is largely focussed on materials and process improvement, such as sorbents and solvents that capture CO₂ more quickly, more effectively and more selectively than those currently used, as well as materials that can last longer through more cycles. R&D in industry works on these same problems but also has a major focus on learning from current deployments, improving the quality of materials, and understanding the impacts of local conditions on processes and equipment. Several DAC companies are working on new processes. One process of particular interest in the UK would be electrochemical DAC that runs purely off electricity (as opposed to requiring heat), advantageous for the ability to run directly on renewable electricity. An overview of the main R&D trends in DAC is provided in Table 5.1 with a mapping of innovation areas shown in Figure 5.1. This overview is based on an initial literature review of DAC research that was then discussed with industry experts to capture their opinions and insights. A more detailed version of Figure 5.1 and more detail on each of the research areas in DAC is provided in Appendix B.

Table 5.1: Overview of research and development trends in DAC.

Figure 5.1: Research and development areas in DAC.

Limiting factors for DAC deployment

The key limiting factors that came out in discussion with expert interviewees were cost and supply of green energy, plus demand for DAC through a stable, long-term market. Requirements on industries to use captured carbon, such as the UK SAF mandate, would provide market confidence, encouraging investment and enabling scale up. An overview of limiting factors is provided in the sections below with more detailed information provided in Appendix C.

Energy demand and cost

The high energy demands for DAC are expected to limit scale up, due to high energy costs and associated infrastructure constraints, such as a large connection to the electricity grid. A 0.5 Mt DAC plant would require around 1 TWh of energy, 20% electricity and 80% thermal energy. If the heat was supplied by heat pumps, that value could be brought to around 0.6 TWh of electricity per year. Assuming a flat load profile (i.e. the electricity demand is flat instead of varying across the day, 0.6 TWh would be around 68 MW in terms of connection capacity, in line with other large industrial sites or data centres.

Carbon intensity of electricity and fuel

The carbon intensity of electricity has a significant impact on the levelised cost of removal (LCOR) as the more carbon intense the electricity is, the more of the captured carbon is assigned to offsetting the source electricity. The grid carbon intensity does not directly affect the cost of capturing CO₂, the levelised cost of DAC (LCOD), but does affect the net CO₂ removal and the LCOR. The distinction between these two becomes important if DAC is being considered from a CO₂ removal point of view or simply as CO₂ as a product.

The carbon intensity of the UK electricity grid is expected to fall from 213 kgCO₂/MWhe in 2019 to 6 kgCO₂/MWhe in 2040. This has the effect of decreasing the LCOR by 28%.

Demand for CO₂

The main market for DAC is currently voluntary carbon offsetting, which is a purely voluntary market without security of demand.^[1]

The EU and UK SAF mandates offer major long-term markets for DAC, with both mandates stating an intention for a portion of SAF to come from DAC over time. These potential markets are explored in detail in section 9. Beyond e-fuels, other major emerging markets are construction materials and CO₂ as a chemical feedstock. Existing CO₂ markets such as the food and drinks industry are also of interest but would largely rely on companies looking to advertise their green credentials to offer a market for DAC.

Policy and government procurement were seen as major drivers here. Current carbon price forecast and emission penalties are not currently high enough to drive demand for DAC.

Planning restrictions

A 0.5 Mt DAC plant would be considered a major development under Scottish planning law, the average planning time for major development projects in Scotland in 2023/24 ranged widely from 22 weeks for projects with processing agreements compared to 53 weeks for those without (Scottish Government, 2024). Very roughly, delays impact project costs by 1%-2% per month, but the Scottish Government was praised in some of the engagements within this study for being dynamic and working with organisations to progress projects.

Geographical requirements

The main geographical requirements for DAC are to be near or connected to low cost, low carbon electricity with a high load factor and near transport, storage or usage of CO2.

The impact of climate on DAC is still not fully understood. Modelling indicates that cooler, drier climates could be techno-economically favourable for solid DAC, while warm and humid climates could be favourable for liquid DAC (Sendi, 2022). The UK is considered a cool and humid climate, which slightly reduces the productivity (i.e. how effectively the CO2 is captured) due to competition with water for adsorption to the surface. This increases energy requirements, but the overall impact is less than 10% in terms of levelised cost of DAC compared to a cold and dry climate. This is a much smaller impact than many other factors and technologies/materials could be optimised for different climates.

Transport and storage

The availability of CO2 transport and storage facilities is expected to be a major limiting factor, especially in the short term. The Storegga facility under the North Sea, planned as the first major CO2 storage site in Scotland, was due to be operational mid-2020s but progress appears to be stalled. Placing DAC sites near utilisation sites will minimise transport and storage requirements, the location flexibility of DAC is considered a major advantage.

Supply chain requirements

The supply chain will need to scale up. There are no major blockers foreseen but a bottleneck in the supply chain can be a risk to scale up. The only material that DAC could use a significant portion of supply and therefore the most likely to cause a bottleneck in the system are amine-based sorbents for solid DAC, currently mainly used in smaller quantities in the pharmaceutical industry.

Commercial sensitivity and maturity

Commercial sensitivity was seen to be a limiting factor in the scale up phase and optimising DAC processes, especially when optimising alongside other technologies like green hydrogen and e-fuel production. The European Marine Energy Centre (EMEC) was noted as an advantage in Scotland as they are very open to partnerships, knowledge sharing and demonstration projects.

Cost of DAC

Reference scenario

This study developed a reference scenario which aligns with ‘Pathway 3’ of the Scottish Government’s ‘Negative emissions technologies (NETS): Feasibility Study’ (Scottish Government, 2023). This pathway assumes that policies and mechanisms are implemented by the UK and Scottish Government which result in high carbon capture and NETS deployment. The 0.5 Mt capacity for the reference scenario has come from the NETs study based on the Storegga and Carbon Engineering project, which was proposed to be built in the late 2020s with assumed minimum capture rate of 0.5 MtCO₂. This project was intended to be operational by the mid-2020s but is currently stalled.

Reflecting that current DAC deployment plans in Scotland are behind what was set out in the NETs study, the reference scenario in this study has been run for year 2040, in recognition that we are unlikely to see substantial deployment of DAC in Scotland in the short term. Our model accounts for reducing costs of DAC over time, incorporating the impacts of ‘learning by deployment’ by assuming a ‘learning rate’ on CAPEX, energy requirements and solid adsorbent cost.

Our modelling approach follows that of Young et al. (Young, 2023) with costs converted from USD to GBP using a ratio of 0.8 with key values set out in Table 7.1 and more detail given in Appendix D. A key assumption for year 2040 is the level of global deployment assumed for this year. This, along with the learning rate, determines the level of cost reduction from the ‘First-of-a-Kind’ (FOAK) plant. The 2040 deployment assumption is 15 Mt combined for both solid DAC and liquid DAC which is based on a global technology diffusion rate (i.e. how quickly the deployment capacity increases each year) of 25%. This value is high, above the average technology diffusions rates but still results in DAC deployment values below those projected elsewhere, reflecting an ambitious but realistic scenario.

The modelling of process energy requirements assumes the cumulative capacity of DAC deployed up to 2040 has improved process efficiency, reducing the energy requirements from a first-of-a-kind (FOAK) plant to an Nth-of-a-kind (NOAK) plant. The FOAK energy estimates for solid DAC are based on operational data from the Climeworks Orca plant (4 kt), while liquid DAC is based on academic literature and modelling (Keith, 2018).

Table 7.1 summarises the energy requirements of the solid and liquid DAC processes. The magnitude and split of electricity vs thermal energy across the two technologies is similar, but the liquid technology requires high-grade heat (circa 900^oC), whereas the solid technology requires lower grade heat (circa 100^oC) and therefore could be supplied by a heat pump rather than combustion of a gas. Assuming a COP of 2, the heat pump would use 0.75 MWh of electricity to produce the required 1.5 MWh_th of thermal energy.

While a heat pump was chosen as the solid DAC heat source other sources of heat such as natural gas or hydrogen may also be used. Likewise for liquid DAC process natural gas was selected as the heating fuel with electricity supplied by the national grid but the process could be configured to generate electricity from natural gas in a combined-cycle-gas-turbine or substitute natural gas entirely for hydrogen or electricity. Alternative heat sources are explored further in section 7.2.4.

Table 7.1: Key inputs for the solid and liquid DAC processes built in 2040

Estimating the cost of DAC

The values in the cost modelling and associated sensitivities are presented as two different metrics: the levelised cost of DAC (LCOD) and the levelised cost of removal (LCOR). The LCOD is the cost to remove a certain amount of CO₂ from the air, the LCOR takes account of the emissions associated with the energy used to power the DAC plant e.g. from electricity generation or the burning of natural gas. The figures presented in this section primarily show the LCOD as this is the most relevant metric when considering costs and markets of DAC CO₂; the LCOR is also marked on the figures to provide additional insight.

A breakdown of the contributing costs to the overall LCOD of solid and liquid DAC is shown in Figure 7.1. The effect of ‘learning rate’ and decarbonisation of the electricity grid is highlighted, with significant cost reductions from the estimated costs of a FOAK plant and a plant built in 2040. In 2040, this model assumes a combined global deployment of solid and liquid DAC of 15 Mt, split evenly between solid DAC and liquid DAC; this means that the learning rates applied to each technology are equivalent to 7.5 Mt of global deployment.

For solid DAC, the levelised cost is estimated to decrease by 75% from £2,253/tCO₂ to £557/tCO₂, while liquid DAC decreases by 25% from £453/tCO₂ to £337/tCO₂. The LCOR (shown as diamonds in Figure 7.1) is especially high for a solid DAC FOAK plant and changes significantly by 2040 as the UK electricity grid decarbonises from 213 gCO₂/kWh to 6 gCO₂/kWh.

The largest contributor to overall cost is variable OPEX, consisting of energy, water and sorbent replacement costs. Variable OPEX is significantly higher for solid DAC due to the use of electricity to supply process heat. Electricity is 3.8 times more expensive than natural gas producing heat and 1.8 times more expensive than via a heat pump (COP = 2) than a calciner used in the liquid DAC process. However, using a heat pump enables the use of zero/low carbon electricity. If natural gas were to be used instead in the solid-DAC process the combustion of the fuel would release CO₂ and increase the cost of DAC per tonne of CO₂ captured.

Natural gas is required in the liquid DAC process due to the high temperature requirements, in this case the emissions from natural gas emissions are captured within the DAC process. The use of alternative sources of heat is discussed further in section 7.2.4.

CAPEX costs were also higher for the solid DAC process (£109/tCO₂) compared to liquid DAC (£65/tCO₂). Since financing and fixed OPEX are fixed percentages of the CAPEX cost, these two are higher in the solid process.

Figure 7.1: Levelised cost for solid DAC and liquid DAC, showing breakdown by cost component.

Sensitivity analysis

A one-at-a-time sensitivity analysis was completed for the reference scenario, where a 20% increase or reduction was applied to a variable, holding all others constant, to see the impact on LCOR. Additional sensitivities were completed to assess the impact of changing energy price and waste heat usage by 50% and 100%. The results are shown in Figure 7.2, with negative values representing a reduction in cost. Waste heat costs are difficult to estimate and are usually process specific; for this analysis waste heat is assumed to be zero cost to represent the maximum potential benefit. The analysis highlighted that solid DAC was most affected by the operational capacity factor, see Figure 7.2 below.

Changes in the price of electricity and the proportion of heat from waste sources had a larger impact on the LCOD of solid DAC than liquid DAC, as solid DAC has nearly double the energy cost than liquid DAC per tonne. A 100% change in the price of electricity (zero cost or doubling the cost) impacts the overall cost of solid DAC by 46% and liquid DAC by 23%. The use of waste heat is also more impactful in the solid process, a similar 100% change reduces the overall cost of solid DAC by 32% and liquid DAC by 23%. It is also unlikely waste heat will be able to replace a significant proportion of liquid DAC heating simply due to the very high temperatures required for the liquid DAC regeneration process. A change in capex cost was slightly more significant in liquid DAC since capex made up a higher proportion of the total cost; changing the CAPEX cost by 20% impacts the solid DAC process by 7% and the liquid DAC process 8%.

Both electricity costs and waste heat utilisation were selected for a further, more detailed sensitivity analysis not only because they are major influencing factors, but because accessing those savings is realistic for a DAC plant in Scotland.

Figure 7.2: The sensitivity of levelised cost of DAC to changes in variables

Electricity price

In section 7.2.1 the price of electricity has been highlighted as the most significant factor affecting the cost of both solid and liquid DAC. A number of possible scenarios were modelled to assess the effect of electricity price on LCOD. These scenarios include:

• Reference scenario price of grid electricity £187/MWh (Climatescope, 2024)
• 2040 Green Book estimate for electricity price £111/MWh (DESNZ, 2024)
• Price of electricity from onshore wind under a contract for difference tariff of £73/MWh (DESNZ, 2023)
• No cost renewables £0/MWh

As shown in Figure 7.3, because the solid DAC process uses electricity for heating, changes in electricity prices have a significant impact on the cost of solid DAC. The maximum achievable reduction in LCOD is 46% for solid DAC to £304/tCO₂ and 23% for liquid DAC to £260/tCO₂, however this relies on zero-cost electricity from a renewable energy source such as wind or solar.

More plausible electricity pricing scenarios such as private wire wind or the 2040 Green Book also significantly improve the LCOD of solid DAC and reduce the cost difference between solid and liquid DAC. By using electricity from onshore wind with a typical feed-in-tariff cost of £73/MWh there is the potential to reduce the overall cost of DAC by 28% and 14% for the solid and liquid processes respectively. However, this may result in longer periods of downtime due to low wind speeds. As shown in Figure 7.2, the LCOD is highly sensitive to the capacity factor and periods of downtime should be avoided.

Using the Green Book estimate for the price of electricity in 2040 has a smaller impact on the overall LCOD, reducing the solid and liquid process costs by 19% and 9%, respectively.^[2]

Figure 7.3: The effect of electricity price on the LCOD of solid and liquid DAC.

Carbon intensity of electricity

The carbon intensity of the fuel used for DAC has no direct impact on the cost of DAC and therefore has no direct impact on the LCOD; however, it does impact the LCOR, i.e. the net cost of removing one tonne of CO₂ from the atmosphere. The LCOR calculation includes the carbon emissions associated with energy use, the impact of which is shown in Figure 7.4. Using a 2024 grid carbon intensity which averaged 213 gCO₂/kWh has an estimated cost of £775/tCO₂. If the carbon intensity of the electricity grid follows DESNZ green book projections and falls to 6 gCO₂/kWh in 2040 (DESNZ, 2024), this would reduce the cost of solid DAC by 28% and liquid DAC by 8%. The decarbonisation of the electricity grid can therefore be considered a necessity for Scotland to be a suitable location for solid DAC when compared to other global locations. Liquid DAC is less sensitive to the carbon intensity of electricity as it uses natural gas for heat process requirements. However, the associated combustion emissions must be successfully captured in the process and the upstream fugitive emissions of natural gas extraction must be considered.^[3]

Figure 7.4: The effect of electricity grid carbon emissions on the LCOR of solid and liquid DAC.

Heat source and integration of waste heat

The LCOR can be significantly impacted by the energy vector used to provide process heating, shown in Figure 7.5 . Electricity, natural gas and hydrogen were considered for each process as well as the utilisation of waste heat.

In the reference scenario, the solid DAC process uses a heat pump to provide the target temperature of around 100°C. Using natural gas for solid DAC heating instead of electricity increases LCOR because of the emission released during combustion. While using green hydrogen does not release any further emissions during combustion, the higher cost of hydrogen compared to natural gas increases the LCOR.

In the liquid DAC process, emissions released from natural gas combustion are captured as part of the process. Natural gas may be replaced with hydrogen as a low-carbon alternative, although the higher cost of hydrogen outweighs the lower carbon emissions and increases LCOR overall.

The utilisation of waste heat is beneficial for both the producer and user of the heat. Waste heat can often be purchased at low cost and is considered as low or zero carbon. Using waste heat would reduce the amount of electricity or natural gas needed for heating, lowering fuel costs and avoid emissions from fuel combustion or electricity generation. However, the extent waste heat can be utilised is limited by the temperature of the source. Since Liquid DAC requires high temperature heating, the proportion of heat that can be supplied from waste heat is significantly lower than solid DAC. For each waste heat source discussed, further details related to calculations and size of plant needed to provide the waste heat are provided in Appendix H.

The viability of using waste heat from sources such as manufacturing processes, energy facilities, or data centres depends on the individual site and process. Both the cost and temperature of heat available influence the potential benefit of reducing the LCOR. The price of heat is subject to commercial negotiations and difficult to estimate. A no-cost waste heat source which can provide 100% of process heat has been modelled to show the maximum theoretical benefit to the solid DAC and liquid DAC processes.

One potential supplier of waste heat is the production of hydrogen via electrolysis. This is most impactful in solid DAC since the 80°C heat from hydrogen production can provide a significant proportion of the process’ thermal energy requirements, reducing the overall LCOD by 26%. There is limited impact on the liquid DAC process due to the high-temperature requirements of around 850°C (Sodiq, 2022). Using waste heat to provide heating up to 70°C and natural gas up to the final temperature of 850°C has a limited impact, only reducing LCOR by 2%.

E-fuel production is another potential source of waste heat. The E-fuel process has an operating temperature ranging from 200°C-240°C (Speight, 2016). This could provide the entire thermal requirement of the solid DAC process, reducing LCOR by 32% (Speight, 2016). As with waste heat from hydrogen, waste heat from e-fuel production can only supply a small proportion of the overall thermal energy of liquid DAC, reducing overall LCOR by 6%.

Figure 7.5: The effect of fuel type on the cost of solid and liquid DAC

Financing costs

An additional sensitivity was performed to understand the impact of financing costs on the cost of DAC. The reference scenario in this study uses financing costs of 3.5%, in line with social discounting rates (DESNZ, 2024).The values in Figure 7.6 show the impact of financing rates at more commercial levels of 10% referred to as the weighted average cost of capital (WACC) (UK Government, 2021). In this sensitivity, the cost of both solid and liquid DAC is increased significantly by the increase in required rates of return on capex investments. The cost of solid DAC is affected more than liquid DAC, with the LCOD of solid DAC increasing from £557/tCO₂ to £642/tCO₂, an increase of 15%; liquid DAC increases from £337/tCO₂ to £404/tCO₂, an increase of 20%. This sensitivity illustrates how the cost of DAC will depend heavily on how the initial capex is funded.

Figure 7.6: The effect of financing rates on the cost of solid and liquid DAC.

Additional costs

Purification

The DAC techniques detailed in this report have been developed with storage as a key market, which requires high levels of purity to minimise how much non-CO₂ is stored. Climeworks reports minimum CO₂ concentrations of 95% although concentrations of 99.9% are discussed in literature (Climeworks, 2022; Ozkan, 2021). These very high concentrations may require additional purification steps but for the purposes of this study, purification costs are assumed to be within the overall DAC costs presented here and additional costs are not added in.

For CO₂ markets, the type of impurities will be important especially for applications within the food and drinks industry. Most of the ‘impurities’ in DAC CO₂ are nitrogen and oxygen left over from the air; more problematic impurities would be from the DAC process such as amines from the sorbents. These impurities would have an impact on the markets for DAC, most notably for food and drink.

Transport

A recent CXC report “Onshore and inshore storage of carbon dioxide” discussed CO₂ transport costs based on literature and discussion with industry, coming to a value of £20-£24/tCO₂ for a 100-mile round trip (ClimateXChange, 2024). These values would be a significant portion of CO₂ costs when CO₂ costs are in the region of £50-£100/tCO_2. Estimated DAC costs are in the region of hundreds of pounds per tonne, so transport costs are less influential. Transport costs would become significant again if carbon pricing was used to bring DAC costs down.

Profit

Profitability information for UK companies is published by the Office for National Statistics with an average for private, non-financial companies consistently around 10% (Office for National Statistics, 2024). It could be argued that DAC would need a higher profit margin as it is a new technology and carries a higher risk, or that finance may be offered to ‘green’ projects at a lower rate by investors seeking environmentally friendly investments. The UK SAF mandate buyout price includes a 20% price premium above expected e-SAF production costs, reflecting that the market is early-stage.

The average UK value of 10% is used to assess profitability in this study. With the cost of capture for DAC in 2040 projected to be in the region of £550/tCO₂, the profit margin would be around £55/tCO₂ bringing the cost of DAC in the market just over £600/tCO₂.

International Comparison

To understand Scotland’s potential for large-scale DAC deployment, the cost to capture carbon in Scotland has been compared against the other countries. Electricity costs, natural gas costs and labour costs have been changed for each country to reflect building DAC plants internationally. Further details are provided in Appendix F.

It is difficult to estimate the future cost of DAC in other countries due to the limited amount of data publicly available on future costs and carbon emissions i.e. there is not a UK Green Book equivalent for all countries. However, current values for energy costs and carbon intensities are available therefore the cost of DAC in different countries in this section has been compared using the same inputs as in the reference scenario (e.g. learning rates have been applied out to 2040, 15 Mt of global DAC deployment is assumed) but the electricity cost and carbon scenarios are from 2024 data. This mix of projected and current data means that the values themselves are likely to change over time but we would expect the trends to remain similar, i.e. countries that countries with very low carbon electricity now will continue to do so, countries with high carbon electricity will take longer to decarbonise their electricity systems.

International comparison for solid DAC

Figure 8.1 presents an estimation of the LCOR for solid DAC in 2024 for various countries. Two points are shown for the UK as a whole: one showing where the UK would sit in 2024 as a comparison against other countries 2024 data, and one showing where the UK would sit in 2040 when the electricity grid has largely decarbonised.

The most competitive locations for solid DAC are those with both low-cost and low-carbon electricity. Iceland and Canada have either significant geothermal or hydro-electric resources, producing electricity with a cost below £100/MWh and carbon intensity below 80 gCO₂/kWh. As a result, these locations have the lowest estimated LCOR ranging between £381/tCO₂ and £434/tCO₂. Whereas locations with high electricity grid carbon intensity like Oman and Texas have some of the lowest electricity costs but the highest LCORs. In terms of DAC capturing and using CO₂, it can be argued that it is the LCOD that is important, purely the cost of capturing the CO₂; however, where DAC is being used for a climate benefit (even if the CO₂ is to be used), it is the LCOR that is relevant.

Scotland has a lower LCOR than five of the thirteen locations assessed. With a relatively high electricity price, the UK is generally only competitive against locations with significantly higher carbon intensity. The focus on LCOR means that Scotland would be a more attractive location for solid DAC than Oman or Australia, despite higher electricity costs. This picture could change over time, for example if the grid in Australia rapidly decarbonised.

The dashed lines in Figure 8.1 show the impact of the cost of electricity in the UK on the LCOR to illustrate how changes in electricity costs would affect the relative competitiveness of DAC in the UK. These lines show that in order for Scotland to become competitive with Iceland, electricity prices would need to be around a quarter of what they are now, more in the region of £40/MWh, a relatively similar picture for the UK as a whole in 2050 once the grid has largely decarbonised.

Figure 8.1: The influence of electricity price on the LCOR of solid DAC across international locations.

International comparison for liquid DAC

The cost of liquid DAC for the same selected locations is shown in Figure 8.2. This analysis shows that countries that are net exporters of gas e.g. Norway, Oman and Texas are estimated to have the lowest LCORs. The UK’s high gas prices result in the highest LCOR out of the locations assessed at £368/tCO₂. The reliance on gas to supply heat for the regeneration process means that the carbon intensity of the electricity supply is far less influential for liquid DAC than it was for solid DAC, such that energy costs (particularly gas costs) dominate the trends more than carbon intensities.

Varying electricity prices, as shown in Figure 8.2, has less impact on the LCOR of liquid DAC in the UK than it did on solid DAC as electricity prices make up a smaller portion of the total cost of liquid DAC. As a result, Scotland is not as cost effective as other locations for the deployment of liquid DAC as described in the reference scenario. This is in line with the rule of thumb from Carbon Engineering that the most attractive countries for liquid DAC are those counties that are net exporters of gas.

Figure 8.2: The influence of electricity price on the LCOR of liquid DAC across international locations.

Market opportunities and potential profitability

To understand how profitable DAC could be in Scotland, various potential markets have been assessed. This section focuses on industrial utilisation of CO₂ that might be scalable and viable in Scotland: what the major demand markets are, potential growth in those markets and the potential role for DAC.

This section examines the potential markets for DAC CO₂ within Scotland and the UK. A number of markets are considered, each considered in terms of:

• the size of the current market
• potential growth in demand
• potential competitiveness of DAC CO₂ in the market
• potential market size for DAC CO₂
• potential for DAC CO₂ to be profitable in the market.

The analysis in each section is put in context of demand relative to a 0.5 Mt DAC plant where all of the captured CO₂ is utilised as opposed to stored. In reality, a DAC plant may supply CO₂ for both use and storage. The costs discussed in this section are based on the reference scenario and the sensitivity analysis in 7.1.

Overview of CO₂ markets

The CO₂ market is split into direct uses of CO₂ (e.g. carbonating drinks) and indirect uses (e.g. as a chemical feedstock). The UK consumes around 0.6 Mt of CO₂ per year (Food & Drink Federation, 2019). The key markets for CO₂ in the UK are:

• Food & drink industry
• Fire suppression and extinguishers
• Medical uses
• Industrial and other uses.

Additionally, horticulture uses a significant amount of CO₂ to boost crop yield within greenhouses, but this CO₂ is generally produced as a by-product of gas-powered heating systems onsite. The annual horticultural CO₂ demand in the UK in 2030 is estimated to range from 108–218 ktCO₂, around 20%-35% of current UK demand but this will be very much dominated by demand in England (Ecofys, 2017).^[4] As heat production is moved from natural gas to electrification, alternative sources of CO₂ will be needed, offering an additional CO₂ market. In terms of DAC, Climeworks have previously reported sales to greenhouses but it is difficult to see a major CO₂ market here due the current CO₂ used being a by-product of onsite heat generation and horticulture is not a sector with large profit margins that could absorb significant additional costs (Climeworks, 2015).

The indirect CO₂ market is more difficult find information on, and therefore to quantify, but CO₂ is used as a chemical feedstock for:

• Fertiliser industry
• Polymers and resins
• Synthetic hydrocarbons
• Other chemical intermediates.

The chemical market was not studied in this report due to this lack of information but recent reports have indicated that there could be demand for CO₂ in the UK chemical industry of 0.45 Mt by 2040, increasing to 2.3 Mt by 2050 (Innovate UK, 2024).

The current cost of CO₂

The cost of CO₂ has been very volatile in recent years largely due to major fluctuations in global fossil fuel prices. During the peak high of energy prices in 2022, CO₂ prices reached £2,000/tCO₂ even £3,000/tCO₂. These prices had a major impact on availability and production of products like meat and carbonated drinks in the UK (Energy & Climate Intelligence Unit, 2022). In conversations with expert interviewees as part of this study, current costs in 2024 between £100/tCO₂ – £900/tCO₂ were discussed. These costs still represent a broad range but were generally concentrated at the low end, in the region of £100-£300/tCO₂. The cost of CO₂ depends heavily on the requirements of the use case: the purity level both in terms of CO₂ concentration and the type and concentration of impurities. However, these values provide a comparison range for CO₂ from DAC.

Biogenic CO₂ is seen as a key future source of CO₂ and is generally currently sold for around £100/tCO₂ or a little lower. However, there is a limited supply of biogenic CO₂, which is a key issue for scaling up applications like e-fuels. The NETs study states that the total biogenic CO₂ currently available from existing sites in Scotland is around 3.3 MtCO₂/year with a future maximum of 5.2 MtCO₂/year by 2032 (Scottish Government, 2023).

Food and beverage industries

CO₂ is widely used in food and beverage industries, the primary uses are carbonated drinks, chilling and packaging, transporting food and stunning animals. As other CO₂ sources are reduced, all these markets will need alternative sources of CO₂ but some are more suited to DAC than others. DAC CO₂ is cleaner than combustion sources, making it more attractive for packaging and carbonated drinks. Additionally, products using DAC CO₂ could carry a green premium in the market.

The beverage industry is of particular interest for DAC because of the size of the market and it is possible to see how a product could benefit from being marketed as lower carbon. Packaging and stunning of animals is likely to move to green sources of CO₂ only as required to by law, via organisational targets or due to lack of supply; a green premium for DAC CO₂ is hard to envisage for these sectors. The food and beverage industry is by far the largest user of CO₂ in the UK, accounting for around 60% of the UK’s CO₂ demand, roughly 360 ktCO₂/year (Food & Drink Federation, 2019). The growing focus on sustainable CO₂ sources has brought DAC into consideration, with Coca Cola already investing in UK DAC company Airhive to supply CO₂ to one of its drinks production sites via an on-site DAC plant (AP Ventures, 2024).

Future CO₂ markets in the UK for DAC

The consensus within literature on future markets for CO₂-derived products is that the market size is difficult to predict. However, three key factors were identified for assessing future markets:

• Scalability
• Competitiveness
• Climate benefit.

The climate benefit of a market influences the degree of interest to governments and other organisations seeking to reduce climate impacts.

There are also a number of market segments that consistently appear in literature on using and sequestering CO₂ from DAC in the future:

• E-fuels (see section 9.2)
• Construction materials (see section 9.6)
• Chemicals / plastics.

The 2019 International Energy Agency (IEA) report ‘Putting CO₂ to Use’ highlighted the potential future global markets for CO₂ (IEA, 2019); Figure 9.1 shows their analysis of the key markets set out by future global market size and by potential climate benefit. The largest market is e-fuels, with demand driven in the early stages by SAF via government mandates. As SAF production scales up and carbon prices on fossil fuels rise, e-fuels will have an increasing share of the fuel market. Construction materials are considered to be the CO₂ use with the greatest climate benefits as CO₂ is stored within the materials and not immediately released upon use, as happens with fuels or utilisation in greenhouses.

A key unknown in the projections of future CO₂ demand is how much CO₂ is being recycled and reused onsite, as happens in the horticulture industry, and therefore how much CO₂ may be required in future that is not currently being noted within the CO₂ market. One example is the chemical industry, where CO₂ is reused as a feedstock (Huo, 2022). These uses should be monitored and reviewed over time to understand how they could contribute to demand for DAC CO₂.

Figure 9.1: Figure taken from an IEA report detailing the potential global market size and climate benefits of CO₂ derived products. (IEA, 2019)

E-fuels

Carbon-based (IEA, 2019) e-fuels are considered a major future market for DAC CO₂. Beyond CO₂ storage, e-fuels were the most discussed market for DAC CO₂ during the expert interviews within this project. The term e-fuels (also called synthetic fuels or power-to-liquid fuels, PtL) refers to molecular fuels made using electricity; these could be green hydrogen, ammonia or carbon-based e-fuels that can directly replace fossil-based fuels. These carbon-based fuels use CO₂ as a feedstock for the process and are expected to be major market for DAC CO₂.

Overview

The process for making carbon-based synthetic fuels depends on the type of fuel being made:

• Fischer–Tropsch (FT) process is used to make long-chain hydrocarbons for synthetic aviation fuel, petrol, diesel etc.
• Sabatier process is used for making synthetic methane
• Synthetic methanol synthesis (not generally given another name).

This study largely focusses on outputs from the FT process, that creates a mixture of hydrocarbons of different lengths via a highly energy-intense process (more detail provided in Appendix I). The exact make-up of the outputs can be adjusted to favour certain chemical fractions, for example, if the process is optimised for synthetic sustainable aviation fuel (e-SAF), the kerosene portion can be in the region of 60% of the output. (Wentrup, 2022)

E-fuels can be considered carbon neutral if:

• The H₂ has come from a carbon-neutral source^[5]
• The CO₂ has been captured either directly from the air or from biogenic sources
• The energy used is zero-carbon, e.g. renewable energy sources.

The requirements on the CO₂ source vary between definitions, with some (including the UK SAF mandate) allowing CO₂ to be supplied from processes where the CO₂ would otherwise have been emitted into the atmosphere (i.e. CO₂ could come from fossil-fuel exhaust systems) and some having a stricter requirement where the CO₂ must come from DAC or biogenic sources. The modelling within this study focusses on e-fuels produced from CO₂ captured via DAC.

Market for FT chemical byproducts

The FT process makes a mixture of hydrocarbons. When the process is optimised, 60%-75% of the FT output can be used directly for liquid hydrocarbon fuels such as e-SAF or e-diesel (Wentrup, 2022; Mazurova, 2023). The other products created in the FT process are generally shorter, lighter hydrocarbons such a naphtha. These byproducts are useful chemicals with their own markets but are not particularly high-value products making it unlikely that a market for the FT side products will have a significant impact on the cost of e-fuels. This picture would change if there was a shortage of such chemicals from current sources or if there was a distinct drive from the chemical industry to move away from fossil-fuel feedstocks.

Aviation, e-SAF

Aviation fuel is a key market for DAC in the form of SAF for three key reasons:

• The aviation sector will struggle to electrify and will still rely heavily on fuels in a net-zero future
• There are already targets for e-fuels in the UK SAF mandate (Department for Transport, 2024a)
• The aviation industry is relatively high value compared to some other markets and has the potential to absorb higher costs where other markets do not.

This section details potential demand for DAC CO₂ based on e-SAF targets and the buyout price set out in the UK SAF mandate (Department for Transport, 2024a). This e-SAF section is the most detailed of the sections on potential CO₂ markets due to the clear targets for e-SAF and a clearer role for DAC. A short sensitivity analysis is included based on academic research. The key assumptions underpinning this section are detailed in Appendix I.

The UK SAF mandate

The UK’s Jet Zero strategy sets out the UK Government’s strategy to decarbonise air travel, to be introduced from 1 January 2025, sets out targets for requirements for the use of SAF and e-SAF for the UK aviation sector (Department for Transport, 2024a).

In 2025, 2% of UK jet fuel demand will be required to come from sustainable sources, increasing linearly to 10% in 2030, then to 22% in 2040.^[6] The mandate for e-SAF starts in 2028, reaching 0.5% in 2030 and 3.5% in 2040. For context, the last reported UK energy demands were 2022, when UK aviation fuel demands were around 12 Mtoe, though expected to increase in the short term in the rebound from the pandemic (Office for National Statistics, 2024). The mandate sets out intended CO₂ sources for e-SAF but does not currently set targets. The SAF mandate states there is potential to increase the target percentages for e-SAF if market conditions allow.

More information and a comparison with the EU SAF mandate is provided in 12.1.23.

Demand for e-SAF

The UK SAF mandate allows us to project demand for e-SAF and consequently for DAC CO₂. Figure 9.2 shows the projected e-SAF demand for the UK (left) and Scotland (right) based on the targets set out in the UK SAF mandate. These demands shown in Figure 9.2 are calculated using projections for the aviation sector from the UK Committee on Climate Change’s 6^th Carbon budget based on analysis carried out in 2019 (Committee on Climate Change, 2020). The figures show that demand for e-SAF in Scotland reaches above 0.04 Mtoe by 2040, around 7% of the equivalent values for the wider UK at 0.55 Mtoe by 2040.

Figure 9.2: Projected e-SAF demand for UK (left) and Scotland (right) broken down by aviation sector i.e. domestic, international and military.

Figure 9.2 shows the split of demands by domestic, international and military according to the splits from the Committee on Climate Change (CCC) 6^th Carbon Budget. The splits show Scotland has a much higher demand for fuel for domestic flights than the rest of the UK and that military demand is only a small portion. The Royal Air Force has been involved in the development and testing of synthetic fuels in the UK and could be a leader in future demand for e-SAF. However, with military demand being such a small portion of demand, the portion of e-SAF used by the military would have to be many times higher than the SAF mandate to add significant demand to the market. There is currently no indication that the military has such plans, though it could continue to be of notable benefit in supporting demonstrators and initial deployments.

Demand for CO₂ for e-SAF

The demand for e-SAF will create a new market for CO₂ but the portion of that CO₂ that will come from DAC is not yet clear. Figure 9.3 show the expected CO₂ requirements for e-SAF production based on the assumptions in Table 12.7 in Appendix I. By 2040, the demand for CO₂ for SAF in the UK would reach around 2.6 MtCO₂, with demand in Scotland around 0.2 MtCO₂. By 2050, this value would increase to around 4.4 MtCO₂ for the UK and 0.3 MtCO₂ for Scotland. These values seem small compared to the potential CO₂ from existing biogenic sources in Scotland (potential estimated at 3.3 Mt), but that biogenic resource is restricted in quantity and location (Scottish Government, 2023; Food & Drink Federation, 2019).

The UK SAF mandate does not state requirements for DAC CO₂ but a 2022 briefing by Transport & Environment noted sub-targets from the EU SAF mandate that gave a target portion of CO₂ from DAC (Transport & Environment, 2022). ^[7] Transport & Environment projected DAC demand based on demand and availability of other sources, “DAC will start to supply CO₂ in 2030 and overtake other carbon sources as the main source by 2035-2040” (page 1). Taking a simple 50% of e-SAF CO₂ demand being met by DAC in 2040 would equate to 1.3 Mt CO₂ demand across the UK and 0.09 Mt CO₂ demand in Scotland, around 20% of the output of a 0.5 Mt DAC plant. However, the high cost of DAC CO₂ makes a 50% target ambitious in terms of supply; the values based on this 50% figure could therefore be seen as an ambitious value or upper limit for DAC demand. Even considering these values as an upper limit, the values demonstrate that demand for e-SAF within Scotland alone will not support a 0.5 Mt DAC plant, but if Scotland was leading UK green hydrogen and e-fuel production then demand for DAC would be higher than demand calculated for Scotland alone.

While this study has assumed that only 50% of CO₂ for e-SAF would come from DAC, the Committee on Climate Change 7^th Carbon Budget (published at the end of this study) appears to have assumed that all CO₂ required for e-SAF comes from DAC, therefore the projected DAC demands for e-fuels are roughly double the values shown here (Committee on Climate Change, 2025).

Something that could significantly affect demand, especially Scottish demand, would be reduction in demand for domestic flights. As we see in Figure 9.2, nearly half of the Scottish e-SAF demand comes from domestic flights, around a quarter of which alone were to London Heathrow, with Belfast, Bristol and other London airports other main destinations (Transport Scotland, 2023). If train and ferry services were improved and made more cost-effective, this domestic portion of demand could reduce.

Figure 9.3: Demand for CO₂ for e-SAF for the UK (left) and for Scotland (right).

Buyout price

The SAF mandate sets targets for SAF and e-SAF as a portion of UK aviation fuel demand but also sets a buyout price for these fuels: the price to be paid by the fuel supplier for failing to meet the SAF and e-SAF percentage requirements. To be competitive, the maximum price for SAF and e-SAF effectively becomes the buyout price + the cost of conventional fuel.

The buyout price in the UK SAF mandate is (Department for Transport, 2024a, p. 46):

• £4.70 per litre, £5,875 per tonne for SAF
• £5.00 per litre, £6,250 per tonne for e-SAF

Potential profitability of e-SAF

The buyout price in the UK SAF mandate effectively sets a cap on the potential profitability of DAC and allows us to understand the range of DAC costs that are compatible with future e-SAF markets. The buyout price set for e-SAF is designed based on modelled costs for e-fuels using DAC and with a price premium of 20% applied to SAF production costs (Department for Transport, 2024b, p. 83).^[8] By design, the e-SAF buyout price should allow for DAC to be profitable, but it does rely on DAC achieving projected cost reductions (though it is not explicit about projected DAC costs). E-SAF made using DAC CO₂ is still expected to be among the most expensive sources of e-SAF (though one of the most scalable) therefore the size of the market for DAC e-SAF beyond mandated amounts will depend on whether other sources can meet demand.

To examine DAC costs compatible with the e-SAF buyout price, Figure 9.4 shows the resultant e-SAF price per tonne for a range of DAC CO₂ values (y-axis, £0 – £1,000) with other costs (e.g. facilities, capex, green hydrogen, energy) aggregated into non-CO₂ costs (x-axis, £1,500/t to £6,500/t). Two dashed lines are shown on the figure marking the buyout price of £6,250/t and the buyout price minus the assumed 20% premium on e-SAF, reflecting the potential margin that SAF producers would add to production costs. Removing the 20% premium from the buyout price of £6,250/tonne gives a production value of £5,100/tCO₂. Conventional jet fuel in the UK costs broadly in the region of £1,000/t, making the maximum compatible e-SAF price in the region of £6,100/t, very close to the buyout price (Jet A1 Fuel, 2024).

A technoeconomic assessment of SAF through PtL estimated DAC CO₂ as around 40% of the total cost of £5/litre e-fuel production (Rojas-Michaga, 2023). This set the non-CO₂ cost around £3/litre, £3,750/t. Using Figure 9.4, we can see that with non-CO₂ costs at £3,750/tonne, DAC CO₂ could be around £400/tCO₂ while being compatible with the e-SAF buyout price. This value of £400/tCO₂ is well below the DAC costs of capture of solid DAC of £550/tCO₂ in the central case discussed in section 0. Additionally, this value is the cost of sale and would therefore need to include the cost of transport, storage and profit. The central ETS price of £142/tCO₂ forecast for 2040 would bring DAC costs into the compatible range but still without a profit margin. For liquid DAC, the central case has DAC costs around £340/tCO₂, below this target compatible value of £400/tCO₂ and therefore with potential for a profit margin. However, it should be noted again that the liquid DAC costs are more uncertain than the solid DAC costs and other international locations are more attractive than Scotland to liquid DAC developers.

In terms of potentially profitable solid DAC scenarios, low-cost electricity would bring the cost of solid DAC down into the £400 region prior to the ETS (Figure 7.3), and waste heat from co-located e-fuel production could bring it lower still (Figure 7.5). Co-location would also remove transport costs. A major advantage of DAC is that it can be flexible with respect to location (access to energy infrastructure will remain a constraint) though transport costs are only expected to be in the region of £20/tCO₂ (value sensitive to distance) (ClimateXChange, 2024). The main location requirements are around space, grid capacity and access to green, low-cost electricity. These are all the same requirements as for e-fuel production so co-location would be a sensible option.

In terms of profit, it could be assumed that DAC was subsumed into the e-fuel production costs, therefore the 20% premium applied to the buyout price would effectively include the profit on DAC. If the DAC was a separately supplied feedstock, an additional 10% profit on top of the DAC costs would be in the region of £40-£55/tCO₂. These numbers are of course highly uncertain and dependent on many factors but they do show a potential for DAC to be profitable as a source of CO₂ for e-SAF.

Figure 9.4: Comparison of e-SAF costs (values shown in bands) depending on the cost of DAC CO₂ (y-axis) and all other costs in e-fuel production (x-axis). Dashed lines are shown for the buyout price listed for e-SAF in the UK SAF mandate and for the buyout price minus an assumed 20% premium placed on production costs by suppliers.

Other impacts on DAC cost, market and potential profitability

The comparison between DAC costs (i.e. LCOD) and the buyout price shows that DAC costs modelled for Scotland could be compatible with e-SAF production. However, there are three key factors that would have a major impact on potential DAC profitability:

• Competition in the market and profit margins, including the cost of conventional fuel
• Cost of H₂
• Cost of energy

Firstly, as discussed above, to be compatible with an e-SAF cost of £6,100/t, DAC costs would need to come down to around £400/tCO₂. From the projections in section 0, liquid DAC could be compatible with these values or solid DAC using either low-cost electricity (Figure 7.3) or waste heat from co-located e-fuel production (Figure 7.5). The projected central ETS price of £142 for 2040 would bring DAC CO₂ costs down into the £100-£300/tCO₂ region. However, e-SAF from DAC CO₂ is still estimated to be one of the most expensive forms of e-SAF. The market will rely on there not being enough e-SAF from other sources, such as e-SAF generated from biogenic CO₂ for DAC CO₂ to be competitive, which the analysis for the UK SAF mandate projects to be around 2-4 times cheaper than PtL from DAC (Department for Transport, 2024b).

Secondly, the cost of H₂ assumed in the central case of the Rojas-Michaga et. al paper is £3.59/kg H₂ (Rojas-Michaga, 2023).The most recent ClimateXChange report looking into green hydrogen production in Scotland, titled ‘Cost reduction pathways of green hydrogen production in Scotland’, estimated green hydrogen production costs in the region of £3.4/kg H₂ by 2045 (£4.1/kg H₂ including transport). (ClimateXChange, 2023) The sensitivity analysis in the ClimateXChange work put 2045 values between £2.8/kg H₂ and £5.9/kg H₂ such that green hydrogen costs remain a major source of uncertainty in costs with the potential to limit the viability of the industry.

Thirdly, changes in the cost of energy would have major impacts on both DAC costs and e-fuel production costs. The Rojas-Michaga et al. study uses central costs of 6p/kWh based on the cost of electricity from wind, around half the projected cost of electricity in the Green Book but in line with the reduced cost electricity values used in Figure 7.3. (Rojas-Michaga, 2023). This low-cost electricity scenario would result in costs for solid DAC in the region of £400-£430/tCO₂, and bring hydrogen costs to the low end of projected costs from the ClimateXChange report (ClimateXChange, 2023, p. 42). The triple impact of low-cost electricity on e-fuel production, DAC CO₂ and green H₂ production makes it a major lever in whether DAC and e-fuel production could be profitable within Scotland.

Shipping

Within the industry interviews conducted as part of this study and within literature, shipping was viewed as a second major market within the UK for e-fuels (International Energy Agency, IEA, 2024). Maritime transport has more options for fossil-free fuels than aviation due to weight and volume of fuel being less of an issue. The fuels discussed in relation to maritime decarbonisation are methane, methanol, hydrogen, ammonia and gas oil/diesel (Lloyd’s Register, UMAS, 2021). These fuels currently come from fossil fuels either directly using fossil feedstock or using fossil fuel energy, but they can be made sustainably, using clean energy and clean feedstocks (i.e. feedstocks obtained with clean energy).

Although there is an understanding that the shipping industry must decarbonise, there is no equivalent to the UK and EU SAF mandates that proscribe the percentage of sustainable fuels or e-fuels. The FuelEU Maritime mandate sets targets for reducing emissions from shipping but not to the level of detail of the SAF mandates (European Union, 2024). This section uses estimations from industry reports to understand the potential market for shipping e-fuels and the potential for DAC CO₂ to be competitive in that market.

Demand for sustainable shipping fuels

Potential demand for shipping e-fuels was modelled based on projected demand for shipping fuels from current UK fuel demand data (Office for National Statistics, 2024), shipping projections from the CCC’s Sixth Carbon Budget (Committe on Climate Change, 2020) and industry projections on future fuel mixes (Lloyd’s Register, UMAS, 2021; Transport & Environment, 2024) . Demand within the UK fuel demand data is broken down into international, coastal and naval. Within this study, it is assumed that domestic shipping will largely electrify, with sustainable fuels prioritised for international shipping. Office for Nationals Statistics (ONS) data gives 2022 values of 8.3 Mtoe of fuel for shipping, split 75% fuel oil and 25% gas oil. Of the total demand, 81% is international, 16% coastal and 2% naval. This 81% demand for international shipping, 6.8 Mtoe, is the focus of the modelling for potential e-fuel demand in this study.

A 2019 report by Lloyd’s Register and UMAS set out a number of scenarios of the potential future mix of low-carbon shipping fuels: a renewable energy dominated pathway; a bioenergy dominated pathway, and a mixed pathway (Lloyd’s Register, UMAS, 2021). The central, mixed pathway (figure shown in Figure 12.812 in Appendix I) shows e-fuels reaching around 20% of demand by 2040 and 30% by 2050 but this covers all e-fuels including hydrogen and ammonia that are not carbon-based. A more recent publication from European Federation for Transport and Environment projects that e-ammonia will be the dominant e-fuel for shipping, covering around 80% of e-fuel demand with carbon-based fuels covering the remaining 20% (shown in Figure 12.13 in Appendix I) The projected mix from the Transport & Environment report suggests only a relatively brief 10-year role for e-diesel with a more permanent transition to e-methanol and e-LNG but with demand for any carbon-based e-fuels not picking up until 2040.

With carbon-based e-fuels not expected to come into the mix of shipping e-fuels until 2040, this would mean demand for carbon-based e-fuels for shipping across the UK would reach about 0.35 Mtoe by 2045, 0.5 Mtoe by 2050. With Scotland representing around 4% of international shipping in the UK, Scottish demand would be in the region of 14 ktoe in 2045, 20 ktoe in 2050. These values are lower than the values projected for e-SAF but ramp much more steeply between 2040 and 2045. Although fuel demand for shipping and aviation is similar, the fact that such a small portion of international UK shipping comes via Scotland (~4%) means that the shipping e-fuel market would be heavily driven by UK demand.

Demand for DAC CO₂ for shipping

Of the potential future fuels for shipping, e-methanol, e-LNG plus e-gas oil and e-fuel oil are the carbon-based molecules that would lead to demand for DAC CO₂. E-gas oil and e-fuel oil production is very similar to that for e-SAF discussed in section 0. The FT process could be optimised for shipping fuels such that a larger fraction of FT output was suitable, potentially up to 75% (Bezergianni, 2013). Synthetic forms of methane (e-LNG) and e-methanol can be produced via similar processes (i.e. combining hydrogen and CO₂). E-methanol and e-LNG are not ‘drop-in’ fuels so would require new ships or retrofitting of propulsion system, although there are some ships that already use LNG.

Figure 9.5 shows projected demand for CO₂ for shipping e-fuels for the UK (left) and Scotland (right). The ranges reflect the high and low renewable energy fuel pathways in the Lloyd’s & UMAS report and the split of e-fuels (i.e. ammonia, hydrogen, carbon-based fuels) projected in the 2024 Transport Environment report “E-fuels observatory for shipping” (Lloyd’s Register, UMAS, 2021; Transport & Environment, 2024).^[9]

The central values in Figure 9.5 show CO₂ demand in Scotland reaching towards 0.1 MtCO₂ by 2050, around 2 MtCO₂ in the UK as a whole. The values shown in these figures are based on CO₂ demand from creating e-fuels in the form of e-gas oil and e-fuel oil via the FT process. E-LNG and e-methanol would require similar amounts of CO₂ as they require less CO₂ per tonne but have a lower energy density, meaning more fuel is needed.

As with CO₂ demand for e-SAF, not all the CO₂ for these fuels would come from DAC. Taking the same assumption as for e-SAF of 50% of CO₂ demand coming from DAC, DAC demand would reach in Scotland 0.05 MtCO₂ by 2050, around 1 MtCO₂ in the UK as a whole. The Scottish demand would account for around 10% of the output from a 0.5 Mt plant, adding to the 20% demand from e-SAF. Scottish e-fuel demands for aviation and shipping would be projected to support a 0.15 Mt DAC plant by around 2040, but again if Scotland was supplying e-fuels to meet wider UK demands, DAC CO₂ demand would be far above 0.5 Mt CO₂.

Figure 9.5: Projected demand range for CO₂ for e-fuel for shipping in the UK (left) and Scotland (right). The central line corresponds to the central ‘Equal mix’ scenario in the Lloyd’s & UMAS report with the coloured areas showing the range from the other scenarios (Lloyd’s Register, UMAS, 2021).

Potential profitability

The analysis above indicates that the market for DAC for carbon-based shipping e-fuels is a broadly around half the size of the market for e-SAF. However, with more options for net-zero compatible fuels there is more potential competition in the market and a lower cost ceiling than for e-SAF. Projections for shipping e-fuel costs are in the region of £1,500-£2,500/t, multiple times higher than current cost for shipping fuel but far below the costs for e-SAF discussed in section 9.3.5 (UMAS, 2023). This difference between projected shipping fuel purchase costs and projected production costs for e-fuels via the FT process presents a major challenge when considering e-fuels from DAC for shipping.

Despite this cost difference, the 2024 Transport & Environment report projects that around 20% of shipping e-fuels will be carbon based, initially mostly e-diesel then shifting to e-LNG with an ongoing role for e-methanol (Transport & Environment, 2024). A similar cost analysis to that carried out for e-SAF is shown in Figure 9.5, showing the resultant price per tonne for e-fuel oil produced via the FT process. The values are shown for a range of DAC CO₂ values (y-axis, £0 – £700) with other contributing costs aggregated (e.g. facilities capex, green hydrogen, energy) into non-CO₂ costs (x-axis, £0 to £3,000). From Figure 9.6 it is clear that e-fuel oil made from DAC via the FT process is highly unlikely to come into the region of £1,500-£2,500/t.

For DAC-based e-gas oil and e-fuel oil to reach these values, not only would DAC costs have to be substantially lower than the central projections in this study, but green hydrogen and e-fuel production costs would also need to be much lower than current estimates. Much lower electricity costs would result in green hydrogen and e-fuel production costs being greatly reduced; zero-cost energy (likely using waste heat and zero-cost electricity) would bring DAC costs into the region of £300/tCO₂, costs that are still far above being compatible with the £1,500-£2,000/t.

The ETS price would have a potential impact on whether shipping e-fuels were a potential market for DAC. In 2040, the central price is projected to be £142/tCO₂e, with the high price at £169/tCO₂e. If the other costs associated with e-fuel production could be brought into the region of £1,500-£2,000/tonne, DAC costs would need to be in the region of £100-£200/tCO₂. These DAC values are still well below the most ambitious estimates for DAC costs presented in section 0, which reach as low as around £300/tCO₂ but with a carbon price of £142/t, fuels produced from DAC CO₂ could potentially enter the market.

In conclusion, shipping e-fuels being a market for DAC CO₂ is likely to rely on a combination of the following:

• Costs of e-fuel production being at the lowest end of current estimates, which would include the cost of DAC CO₂ and green hydrogen being at the lowest end of current estimates
• ETS prices being in the central or high range, or being greatly increased so that it effectively covers the cost of DAC
• If an e-fuel production plant does not have access to biogenic or fossil CO₂, the flexibility of DAC could make DAC CO₂ the most economic (or only) option
• sites were located near renewable energy sources but away from other CO₂ sources such as industrial sites
• Demand for sustainable fuels being high and driving up market prices.

Figure 9.6: Comparison of e-fuel oil costs for shipping (values shown in bands) depending on the cost of DAC CO₂ (y-axis) and all other costs in e-fuel production (x-axis).

Drinks industry

The food and drink industry, and particularly the carbonated drink industry is of interest for DAC for several reasons:

• The food and drink industry is a major UK consumer of CO₂ in the UK
• DAC can produce very pure CO₂ meaning it is suitable for food and drink grade CO₂
• The carbonated drinks industry (e.g. soft drinks and beer) has a high mark up on products, especially compared to an industry like horticulture or construction materials
• There is a market for premium products within the industry.

The market for premium products within the drinks industry is of particular interest as there is potentially a market for products that are greener or more ethical, a ‘green premium’. Typical examples that are already active in the market are organic or fair-trade products. We have used this idea of a green premium to understand how the higher cost of CO₂ from DAC might be absorbed into product costs.

Additionally, there is already proven interest in DAC within the drinks industry with Coca Cola partnering with Climeworks and more recently investing in UK DAC company Airhive to supply DAC CO₂ to replace fossil-derived CO₂ at a production site (AP Ventures, 2024; The Chemical Engineer, 2018).

Current demands for CO₂ and potential demand for DAC

Industry reports suggest the UK food and drink industry consumes in the region of 300-360 ktCO₂ annually (Food & Drink Federation, 2019). As this demand is UK-wide, demand will not be spatially concentrated enough to support a 0.5 Mt DAC plant in Scotland. However, the potential size of the market is still considered and the potential for profitability as it is a market area where DAC CO₂ is of interest.

The primary uses of CO₂ in the food and drinks industry are carbonating drinks, chilling and packaging, transporting food and stunning animals. As discussion in section 9.1.2, as other CO₂ sources are reduced, all these markets will need alternative sources of CO₂ but the carbonated drinks industry is the most interesting for DAC. In Table 9.1, estimations are shown for the demand for CO₂ within the soft drinks industry across the UK. These values add up to only 46-77 ktCO₂ across the UK, information on the portion of this that is attributable to Scotland is not easily available so an assumption of 10% is made, broadly in line with population. A Scottish demand of 4.6-7.7 ktCO₂ would only account for 1-2% of annual CO₂ generation from a 0.5 Mt DAC plant and would therefore not be a major market.

Table 9.1: Calculation of CO₂ requirement for UK soft drink and beer industries.

Potential profitability

The price of CO₂ for utilisation discussed in interviews within this study were in the region of £100-£300/tCO₂ though a broader range of up to £900 over recent years was discussed, with higher values again reported in the media (Energy & Climate Intelligence Unit, 2022). Food-grade CO₂ commands a higher price than industrial CO₂ due to its higher purity requirements.

To understand potential profitability of DAC in this market, we have considered the impact of changes in the cost of CO₂ on the overall cost of the product. The cost of CO₂ is estimated to be around 0.5%-1.5% of total production cost based on the costs in Table 9.1; much smaller than the portion of costs for e-fuels. Figure 9.7 shows the CO₂ costs that would be compatible with 2% and 5% increases in production costs; the values are shown as ranges to reflect fluctuations in current costs, estimated to be £200-£300/tCO₂. The 2% increase could be considered a green premium or simply a change in production costs, a 5% increase is more representative of a green premium that would to be passed on to customers by marketing the product as a green product.

The value of this green premium depends heavily on the product and the price of the product and varies country to country (Boston Consulting Group, 2023). PwC research giving a value of 9.7% for a green premium was focused shopping habits and is therefore more appropriate for the drinks market (PwC, 2024). Consumer research into green premiums gives values around 10% are but the full 10% has not been applied in the analysis here as other aspects of the production would presumably need to be ‘greened’ and the associated costs for those would also need to be included (PwC, 2024).

The most obvious insight from Figure 9.7 is that the projected DAC CO₂ costs in section 0 are comfortably in the ranges shown. This contrast with e-fuels is because CO₂ makes up a much smaller portion of the total cost than it does for e-fuels; drinks products that use less CO₂ can naturally accommodate higher costs. When CO₂ costs spiked, media reported that costs reached £2,000-£3,000t/CO₂, easily increasing production costs by 10% for drinks and understandably causing issues in supply chains (Energy & Climate Intelligence Unit, 2022).

Figure 9.7: Range of DAC costs compatible with the carbonated drinks industry

The scenarios along the x-axis show various combinations of green premiums on drinks from using DAC depending on the percentage production costs CO₂ currently makes up. The range in each scenario reflects uncertainty and fluctuations in current costs, assumed to be in the region of £200-£300/tCO₂.

The values presented in Figure 9.7 demonstrate that the carbonated drinks industry is highly compatible with the cost of CO₂ from DAC and could likely be profitable. However, the market size means that this would only be on the scale of a few kilo tonnes.

Construction materials

Construction materials come up consistently in discussions about carbon storage and utilisation because it is large-volume market and offers multi-decade storage potential. Additionally, construction materials offer an early market for CO₂ while other markets, like e-fuels, are still developing. However, a market size or understanding the role of DAC is difficult to quantify. Additionally, construction materials are a low-value industry, making absorbing additional costs very difficult.

A key niche for ‘green’ construction materials is turning waste products into useful materials. Carbon8 make use of reactive residues come from processes like energy from waste, biomass, and the steel and paper industries, reacting them with CO₂ captured from the same process to form aggregates that can be used in construction (Carbon8, 2024). A major financial value in this process comes from savings in waste disposal. These savings, combined with a market for the product and a carbon price, create a market for the CO₂-storing product.^[10] Currently, the CO₂ used is collected onsite via CCS, limiting the role of DAC. However, as the market grows, so would the demand for CO₂; not all sites may be suitable for CCS and a portion may choose to bring in CO₂ from elsewhere, creating a role for DAC.

For cement and concrete, CO₂ can be stored when the material is cast or when a structure is demolished and the concrete is reused. Quantification of the CO₂ stored in concrete needs to be carefully considered: standard concrete contains some carbon and naturally reacts with CO₂ in the air. For carbon capture and storage, the material has to store additional carbon to the amount that it would in standard use. Adding CO₂ to cement has been advertised as enhancing the strength of the concrete but this depends heavily on the production process to ensure the concrete is not weakened instead (Fu, 2024).

Potential role for DAC CO₂

There are currently no figures for projected CO₂ demand in the construction industry and even Scotland-specific demand for construction materials is difficult to find data on. The UK datasets on demand for building and construction materials aggregates demand for Scotland and Wales, ranging from 6%-9% of UK demand (Department for Business and Trade, 2024). The IEA’s 2019 report ‘Putting CO₂ to Use’ stated that companies creating products from industrial waste and CO₂ were consuming around 75 kt/year globally, with UK-based Carbon8 storing 5 ktCO₂/year in 2019 (IEA, 2019). By 2021, Carbon8 was producing 300 kt/year of aggregates, which would capture around 10%-20% CO₂ per weight, therefore storing in the region of 10-20 ktCO₂/year (University of Greenwich, 2021). However, this CO₂ demand is largely met by the processes that produce the industrial waste and additional demand for CO₂ may be limited.

The role for DAC in this process would be where there is not sufficient local CO₂ demand or where onsite capture is not practical, for example it is too expensive and disruptive to install carbon capture, or space is limited. In these cases, DAC CO₂ could be transported, but costs would need to be competitive.

Potential market size

Aggregates

Scotland produces around 21 Mt of aggregates per year, mainly from quarries but also from construction and demolition waste. The Carbon8 project generates aggregates from waste materials, with a market size more likely to be dictated by the availability of reactive waste materials than driven by the overall size of the aggregates market.

If we take energy from waste (EfW) as an example: 1.62 Mt of waste was incinerated in Scotland in 2023, a four-fold increase since 2011 (Scottish Government, 2024). The waste output from EfW is 20%-30% of the input by weight, therefore around 0.3-0.5 Mt of EfW waste outputs is generated annually in Scotland. If we again apply a 15% CO₂ uptake to this waste output, we have a CO₂ demand in the region of 0.05-0.07 Mt of CO₂. Most of the CO₂ needed for this process would be expected to come from the EfW process itself, even if 10% of this demand came from DAC to top up local supply, which would only generate a few kilo tonnes of DAC demand annually. Therefore, demand from processes industrial waste is not likely to contribute significantly to DAC demand in Scotland and would not be a driver for a 0.5 Mt DAC plant.

Cement

The UK consumes in the region of 15 Mt/year of cement, with Scottish and Welsh demand together accounting for 6%-9% annually (Statista, 2024). If we take Scottish consumption to be around 4% of the UK’s, we have a value for Scottish cement demand of 0.6 Mt/year. The potential CO₂ uptake of cements depends on the chemical make-up, ranging between 8% and 25%, here we take 15% as a central value. (Hanifa, 2023) The theoretical maximum CO₂ demand for Scottish cement would therefore be around 90 ktCO₂/year. The portion of cement that is treated to store CO₂ will depend on a market for green products, driven somewhat by consumer choice but most likely by legislative requirements to use lower-carbon building products.

As with aggregates, most CO₂ for this process would be expected to come from carbon capture on local process, rather than DAC, and even then, local DAC with minimal transport may be preferable. As such, cement will not be a major driver for a DAC plant in the region of 0.5 Mt but could contribute early demand or drive demand for smaller, dispersed DAC plants.

Cost compatibility and potential profitability

Industry discussion within this project indicated that current CO₂ prices in the region of £100-£300 were compatible with the market for incorporating into construction materials. The high end of this compatible range is at the very low end for projected solid DAC costs in the UK.

As with the shipping e-fuels industry, cost compatibility of DAC is likely to rely on either or both of a high ETS price or legislation. The ETS price would need to make up the difference between the £100-£300 range and the solid DAC price, projected to be in the region of £550, potentially higher if this demand is coming earlier than 2040. The current projected ETS of £142 in 2040 would not bring the solid DAC CO₂ price in line with this range; an ETS price in the region of £250-£350 would be needed to bring DAC prices into this compatible range.

Conclusions

Scaling DAC requires overcoming technical, economic and logistical challenges. Key advances in air contactor design, sorbent efficiency and integration with renewable and waste heat are driving progress. However, high energy demands, market uncertainty and supply chain constraints remain significant barriers. For DAC to fulfil its potential, policy intervention, infrastructure development and a stable CO₂ market will be essential. With continued research and real-world deployment, DAC can play a pivotal role in meeting net zero goals.

The key aim of this study was to understand whether a DAC plant would be profitable in Scotland and under what conditions, and to understand the likelihood of those conditions where possible.

Research and development trends in DAC

DAC technology is advancing rapidly, with research focused on enhancing efficiency, reducing costs and improving integration with renewable energy and waste heat. Innovations in air contactor designs aim to optimise geometries and reduce capital costs, while ongoing work on sorbents and solvents targets scalable, cost-effective materials that maximise capture rates and minimise regeneration energy demands. New approaches to regeneration processes are exploring modular, low-energy solutions that can be optimised for climates and operational scales.

Integration with other energy systems is an area of future focus but research so far has been limited, partially by commercially sensitivity around sharing details of processes. Leveraging waste heat from processes like green hydrogen and e-fuel production could significantly offset DAC’s substantial thermal energy requirements but these technologies are also not yet developed at scale.

Limiting factors in DAC deployment

High energy demands and costs remain primary obstacles, with regions offering stable, low-cost energy (e.g., Iceland and Texas) better positioned for deployment than those with higher energy prices, such as the UK. The current reliance on volatile voluntary carbon markets adds further uncertainty, underscoring the need for government policy to provide confidence in a long-term market.

Additional hurdles include planning delays, including the fear of delays and difficulties, and the immature state of CO₂ transport and storage infrastructure. While cooler, drier climates provide marginal advantages, they are secondary to the broader economic and logistical barriers.

Cost of DAC deployment

The most obvious insight from the modelling in this study on the cost of DAC is that liquid DAC is projected to be cheaper than solid DAC in terms of costs per tonne of CO₂ captured because of lower capex costs and lower energy costs. The central scenario in this study projects costs of capture (i.e. not including transport, storage or profit) in the region of £550/tCO₂ for solid DAC and £340/tCO₂ for liquid DAC. This is focussed on Scotland in 2040, assuming a global deployment level of 15 Mt. These central values carry significant uncertainty, particularly to overall learning rates, but also to the cost of key elements such as materials capex and energy costs.

Energy costs are the biggest contributor to the cost of DAC as modelled in this study, accounting for around half of the total costs. Although energy costs are higher for solid DAC than liquid DAC, there is more scope for reducing energy costs in solid DAC through the use of low-cost electricity and waste heat due the fact that solid DAC relies more on electricity and operates at a much lower temperature than liquid DAC allowing a bigger role for waste heat.

The waste heat sources considered specifically in this study were green hydrogen production and e-fuel production via the Fischer-Tropsch process, the process used to make e-fuels such as synthetic aviation fuel from CO₂ and hydrogen. With e-fuels considered a major future market for DAC CO₂, and Scotland considered an attractive location for these industries (especially within the UK), co-location of these three industries is very plausible, especially due to the major impact on the cost of DAC.

The option to use hydrogen instead of natural gas to provide the high temperatures needed for liquid DAC was also investigated. Using hydrogen pushes up the cost of liquid DAC by around 30% but even with this increase it is still cheaper than solid DAC, if that solid DAC is relying on grid-cost electricity.

An additional sensitivity was performed to understand the impact of financing costs on the cost of DAC by increasing the financing rates from 3.5%, in line with social discounting rates (DESNZ, 2024) to more commercial levels of 10% (UK Government, 2021). In this sensitivity, the cost of both solid and liquid DAC is increased significantly by the increase in required rates of return on capex investments highlighting that the cost of DAC will depend heavily on how the initial capex is funded.

International comparison

The cost of solid and liquid DAC in Scotland is compared to other potentially suitable, international locations. While liquid DAC is estimated to be cheaper than solid DAC per tonne of CO₂ removed, the findings of the international comparison showed that Scotland was the most expensive of the regions investigated for liquid DAC, while Scotland was more favourable than many countries for solid DAC. This insight was in line with discussions within expert interviews in this study that indicated that Scotland and wider UK were not target locations for deploying liquid DAC, though this picture could change over time. Additionally, whilst liquid DAC has been estimated to be cheaper, the use of natural gas for its heat requirements may encounter challenges due to societal acceptance and political opposition to the continued use of fossil fuels.

Market opportunities and potential profitability

The conclusions from this study highlighted that there is a future market for DAC in Scotland broadly in the region of 0.15 Mt by 2040, not enough to make a 0.5 Mt DAC plant profitable for utilisation alone. Two key factors could make a plant of that scale profitable: demand for e-fuels from the rest of the UK or generating revenue from sending most of the captured CO₂ to storage. Scotland’s clean energy resources, most notably offshore wind, offer key advantages for allowing DAC to be profitable especially when placed alongside other technologies such as green hydrogen and e-fuel production that could offer waste heat.

Synthetic fuels, especially sustainable aviation fuels (e-SAF), offer the most obvious market for DAC CO₂ in Scotland, though it does not currently have specific requirements for DAC. In this study, we estimate that by 2040, DAC CO₂ demand for e-SAF would be around 0.09 MtCO₂ in Scotland and 1.3 MtCO₂ for the wider UK but these values are ambitious based on DAC supplying a large share of the CO₂ used. The projected cost of liquid DAC would be compatible with the buyout price for e-SAF, with the compatibility of solid DAC relying on the ETS price and potentially lower fuel costs or waste heat to be profitable

DAC demand from shipping fuels was projected to be lower than for e-SAF (~0.05 Mt for Scotland, 1 Mt for UK) due to there being more options for net-zero compatible fuels, with a knock-on effect on the price that would be paid for fuels. Consequently, not only would DAC costs need to be much lower but so would the other costs for e-fuel production, i.e. energy costs and green hydrogen production.

Carbonation for the drinks is a small but potentially highly profitable market for DAC and could support early development. However, the market is small, only a few kilo tonnes in Scotland, so it would not drive demand for a large-scale plant.

Construction materials come up consistently in discussion, but the potential market is hard to quantify, especially in a large-volume but low-margin industry. The demand for CO₂ could be in the region of tens of kilo tonnes but much of this is expected to be generated and reused on-site rather than bought in from DAC. DAC could play a role in topping up on-site supply, but this demand is not likely to drive DAC demand on a large scale.

Future considerations for DAC in Scotland

Below are a set of future considerations for each of the sections within this study, highlighting areas that are likely to evolve over coming years or that could have a major impact on the potential profitability of DAC in Scotland.

Future considerations for R&D:

• Monitor key developments in DAC that would lead to major changes in technology, the most obvious examples being:
• Economies of scale balance against reduced storage and transport costs by building smaller plants locally to CO₂ demand
• Energy demand reductions that could address the high energy costs associated with DAC
• Alternative regeneration technologies where that required less energy or allowed lower regeneration temperature for liquid DAC, eliminating the need for gas and the resultant carbon emissions
• Monitor the insights gained from deployments and whether they affect any key assumptions in DAC cost calculations and market assumptions
• Encouraging and facilitating co-operation between industries such as DAC companies, e-fuel companies and those developing green hydrogen facilities to understand the potential to use waste heat in DAC.

Future considerations for limiting factors:

• Continue to engage with DAC providers, especially with regards to the planning process
• Communicate where there is an expected market for DAC (both geographically and in which markets) and engage with suppliers to understand key limiting factors for that site.

Future considerations for the cost of DAC:

• Monitor global deployment levels and learning rates, two of the major contributors to DAC cost reductions; R&D will feed strongly into learning rates
• Ongoing consideration of energy prices on DAC, and how changes such as zonal pricing would affect DAC costs
• Opportunities to co-locate DAC plants with waste heat sources, particularly green hydrogen and e-fuel production.

Future considerations for the market for DAC CO₂:

• Monitor relevant details within policies, such as the target for DAC CO₂ in the UK SAF mandate
• Seek to understand how DAC demand and generation will be spread across the UK. For example, if e-SAF production using DAC will be focused on a small number of sites, such that a DAC plant in Scotland would a meet a significant portion of UK demand.
• Monitor signalling from maritime agencies and governments on the predicted role of e-fuels in shipping. For example, if ammonia began to be viewed less favourably, the role of sustainable carbon-based shipping fuels would increase
• Engage with the chemical industry to understand the role of externally generated CO₂ in future processes.

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Appendices

1. Additional information on DAC technology

This appendix provides additional information on DAC technologies, focussed on established methods.

Within both solid and liquid DAC, the process itself (solvent/sorbent, regeneration process, mechanical design etc.) varies and is an active topic of research and development. Three methods developed by leading companies Climeworks, Global Thermostat, Carbon Engineering are currently at the furthest stages of development and scalability (IEA, 2024). An overview of the most active areas of research and development are provided and assessed for their potential to improve upon these established methods.

Liquid DAC – Aqueous Hydroxides

The liquid DAC capture process used by Carbon Engineering captures CO₂ from ambient air using aqueous solution of KOH to form potassium carbonate (Sodiq, 2022). The carbonate is subsequently fed into a calciner where KOH is regenerated and CO₂ released in a high temperature, high energy calcination process. The temperatures needed for this regeneration process are around 900°C and above; these temperatures are typically achieved by burning gas, with the released CO₂ captured within the process. These high temperatures are an issue for liquid DAC technologies as heat pumps cannot reach this temperature meaning liquid DAC cannot run solely on renewable electricity.

Solid DAC – Solid Amines

Climeworks and Global Thermostat use a solid amine to capture CO₂ from ambient air. Once the adsorption beds reach the desired capacity, a temperature-vacuum regeneration system (TVSA) heats the beds between 80 – 100°C which regenerates the sorbent and releases CO₂ and water (McQueen et al., 2021). Heat pumps can provide the temperatures needed for solid DAC but not for liquid DAC.

Solid DAC – Solid Alkali Carbonates

This method developed by Heirloom uses a calcium looping method, similar to the liquid DAC method used by Carbon Engineering. Instead of an aqueous hydroxide, solid calcium carbonate (limestone) is heated in a calciner, producing pure CO₂ and calcium oxide. The calcium oxide is arranged in a bed and captures CO₂ passively from the air. Initially this capture stage required up to four weeks to reach the desired carbon uptake but recent innovation and developments has reduced this time to several days (Heirloom, 2022).

Table 12.1: Summary of established DAC technologies.

1. Main R&D trends in DAC

This appendix gives an overview of key current research and development trends in DAC.

Innovation Map

A variety of sources including publications in journals and industry consultations were used to develop a map of trends in research and development in the DAC space. These emerging technologies and methods are presented in the subsequent sections. An overview of the key R&D areas for processes and materials is provided at the start in Figure 12.1, mapping the R&D sectors to technologies and companies.

Figure 12.1: Trends in DAC Research and Development

Air contactors

Air contactors are the section of the system where air is passed through or across the liquid or solid sorbent capture material. Around 20% of the energy demand for DAC is used in this phase, largely as electrical energy for fans and pumps. (McQueen et al., 2021). The main energy demand is overcoming the pressure drop resulting from the input air meeting resistance from components of the system such as the filters. The air pressure needs to be kept high to maintain the concentration of CO₂ and therefore the efficiency of the carbon capture.

Cost contribution to DAC

Air contactor’s contribution to the system capex and overall cost depends on the type of DAC. The Hanson et al. report from 2021 gives the cost of an air contactor for solid DAC of $13 million to $84 million ($1–$8 per tonne of CO₂ removed), for liquid DAC the numbers are less clear but with projected capex values post innovation in the region of $200-$400 million and an ambitious minimum of $30-$60 per tCO₂, a clear issue when trying to get to total costs of $100/tCO₂ (Ozkan, 2022) (Hanson et al., 2021)

Air contactors

With air contactors being such a large cost in liquid DAC, it makes sense that air contactors are a key R&D area for Carbon Engineering. Carbon Engineering highlighted two main areas of development for contactors: reducing capex costs of the contactors and adapting the geometry of the contactors to increase the contact area between the incoming air and the capture agent, thereby increasing capture efficiency. Much of this contactor optimisation work has been done through computational modelling, with a move away from conventional packed columns where the air had to be forced through, resulting in large pressure drops, to structures that better accommodate air flow minimising resistance while providing a large surface area for CO₂ capture e.g. thin, flat sorbent sheets, monoliths, or cooling towers-like scrubbers (Climeworks, 2023). These approaches are being developed in both liquid DAC and solid DAC, reducing electricity demand and increasing capture efficiency.

Passive air contactors

Another area of research is having passive air contactors, where wind or natural airflow drive the interaction between the air and capture material. There is a trade-off here with the capex reduction (up to 25% of the cost of capture) and energy demand reduction versus the reduced capture efficiency and increased capture time (Third Derivative, 2021). There are a number process-based or place-based factors that would make passive air contactors more attractive:

• Sorbents with a high capture efficiency and low cost
• Locations with lots of space and naturally strong airflow/windspeeds
• Locations where airflow is already accelerated, e.g. cooling towers (Noya, 2024)
• Locations with high electricity prices.

A number of startups are investigating this option including Heirloom, Carbon Collect, Infinitree, and Noya. Heirloom have reported that they have reduced the time taken for carbonation of their material from an industry standard of 2 weeks down to 2.5 days. It is not entirely clear how the acceleration was achieved but they are using thin layers spread over multiple levels to maximise contact area while minimising land use. The passive approach means that the air contactors need only <0.05 GJ/tCO₂ (~14 kWh/tCO₂), compared to upwards of 0.5-1 GJ/tCO₂ for other approaches (around 140-280 kWh/tCO₂). (Heirloom, 2022; Third Derivative, 2021)

In 2022, BEIS awarded the Dutch start-up CO2CirculAir B.V. £3 million for their SMART-DAC project, which utilises wind circulation to drive the CO₂ capturing process, as opposed to relying on fans, thereby eliminating energy costs associated with forced air movement (Anon., 2022) The funding was allocated towards the construction of a pilot plant in Larne, Northern Ireland, at the B9 Energy Storage offices. Testing was set to begin in spring 2023, with the facility expected to capture at least 100 tonnes of CO₂ per year, however as of March 2025, according to the company’s website, the project is still under construction (Anon., n.d.).

Sorbents and solvents

Sorbents and solvents are the materials that capture the CO₂, either by being absorbed into the solvent in liquid DAC or adsorbing onto the material surface in solid DAC. Solvents and sorbents are a major area of research in DAC, the ideal capture material would be highly efficient at capturing CO₂, doing so quickly and selectively but also giving up the CO₂ readily with a small change in temperature or pressure, therefore reducing the energy requirements for generation. For the DAC industry, the ideal capture material would also be low cost, easy to produce at scale and be stable throughout thousands of cycles. There is an additional consideration that some materials work better in humid conditions, while some are much worse in humid conditions; this will affect which materials are best suited to which countries/climates and use cases. A summary of potential improvements is given in Table 12.2 with more detail below with the filled cells indicating the advantages of each material.

Table 12.2: Summary of potential improvements in DAC solvents and sorbents, the filled cells highlight the advantages of each material for DAC.

New Amine Functionalised Adsorbents

The development of new amine functionalised sorbents used in solid DAC methods such as the ones used by Climeworks and Global Thermostat have the potential to reduce the energy demand of regeneration and to improve the number of cycles the sorbent can undergo before degeneration (Wang, 2024). Sorbent lifetime ranges in estimates from 0.25 – 5 years (McQueen et al., 2021).The Climeworks process uses 7.5 kg of sorbent per tonne of CO₂ captured with the target of reducing this to 3 kg (Duetz, 2021).

Metal-Organic Frameworks

These physisorbent materials have a porous structure with a high surface area and tuneable properties (Wang, 2024). Tunability means that the material can be more selective to capturing CO₂, as opposed to capturing other molecules like water, an issue particularly in more humid climates (Sodiq, 2022). Climeworks are working with co-producer Svante to create novel air contactors containing MOFs with very high surface areas and lower operational costs. In a recent development, a team at Ecole Polytechnique Federale de Lausanne, Switzerland (EPFL) have developed a new MOF which prevents the CO₂/water competition, selectively capturing CO₂ in wet environments (Sodiq, 2022). In one experiment the energy required for regeneration was comparable to established approaches, using 1,600 kWh_th­ for MOF regeneration.

Zeolites

Zeolites have a similar structure to metal organic frameworks and when tuned appropriately, provide efficient and selective adsorption/desorption of CO₂ in low concentrations due to a number of zeolite intrinsic properties; pore architecture, low price, crystal size and chemical composition (Sodiq, 2022; Siriwardane, 2001; Zukal, 2010). However, selectivity of CO₂ is poor in humid air and the materials degrade through the cycles meaning more research is needed before moving from laboratory scale to industrial scale (Mukherjee, 2019).

Silica Gel

Silica gel materials are also of interest to overcome the issue of absorbing water rather than CO₂. Recently, commercially available silica gels of different pore sizes were grafted onto a triamine to investigate the CO₂ capture performance (Anyanwu, 2020). The grafting process was completed in both dry and wet conditions to assess the effects of moisture on the sorbent’s CO₂ uptake capacity. The capacity of silica gel to capture CO₂ improved by 40% indicating the potential suitability of Silica Gel-based DAC methods for humid climates (Kwon, 2019).

Regeneration Process

Crystallisation

Crystallisation is a potential alternative DAC method that offers low-cost CO₂ separation from sorbents with minimal chemical and energy inputs. This method has been the subject of several research papers, one example uses aqueous guanidine sorbent (PyBIG) to capture CO₂ from the atmosphere, binding it as crystalline carbonate salts which are subsequently separated by filtration and heated to 80-120°C to release the bound CO₂ and regenerate the sorbent, requiring 1410 kWh_th­ (Seipp, 2017). Other studies have used the same method and alternative sorbents with similar results (Brethomé, 2018). Research is currently limited to laboratory scale with overall energy requirements still higher than the optimised Carbon Engineering method (Sodiq, 2022).

Electrochemical methods

These methods are an active area of research and being developed by companies such as Verdox and Mission Zero Technologies (Voskian, 2019) The key advantage of electrochemical methods is that they use only electrical energy, there is no heat requirement. The electrical-only method is appealing for places where the greenest and cheapest energy sources are electric, as opposed to somewhere like Iceland that has cheap geothermal heat.

Electrochemical methods could offer highly efficient and modular solutions for DAC, suitable for various scales of deployment. An electro-swing method being developed at the Massachusetts institute of Technology (MIT) uses specially designed electrodes to capture CO₂ through CO₂’s electrochemistry (Advanced Science News, 2021). The method has shown promising results, working at ambient conditions with low energy requirements of 570 kWh_e per tonne of CO₂ captured. However, the process required CO₂ concentrations higher than the 400ppm found in atmosphere (6,000 – 100,000) as well as reporting a capacity loss of 30% after 7,000 cycles. Both of these factors have currently limited deployment to laboratory scale (Advanced Science News, 2021).

Moisture Swing

Another active area of research companies such as Carbon Collect and Avnos are exploring moisture-swing adsorption processes using ion exchange resins. These systems capture CO₂ efficiently in dry conditions and avoid the need for high energy consumption or a vacuum (Wang, 2024) (Xie, 2024). One recent study estimated a regeneration energy requirement of 377 kWh_th per tonne of CO₂ captured, but acknowledged this did not take into account the precooling process or differences in efficiency at scale (Xie, 2024). The method is suitable for low-purity CO₂ applications like agricultural greenhouses. The method performs poorly in humid conditions and is limited to deployment in arid environments; research is ongoing to improve efficiency.

Integration with waste heat

Solid DAC and liquid DAC both use heat to remove the CO₂ and regenerate the capture material. Approximately 80% of the overall energy demand for both types of DAC is thermal energy, which offers opportunities for using waste heat from other sources (Ge, 2024). The opportunity to use waste heat for DAC was discussed in some of the interviews with industry experts in this study. EMEC highlighted that green hydrogen production and e-fuel production both generate waste heat and are technologies that would make sense to develop alongside and co-locate with DAC.

There are a number of considerations for waste heat incorporation with DAC:

• Amount of waste heat, e.g. in GWh
• Temperature of waste heat
• Concentration, e.g. at a single location or dispersed
• Cost, including the cost of transporting or concentrating the heat
• Accessibility, also linked to cost
• Consistency of supply, within a day or year but also over the lifetime of the plant
• Competing demands for the heat
• Carbon intensity of the heat

A 2020 report by BRE for CXC considered sources of waste heat in Scotland, split by low-grade and medium-grade sources as summarised in Figure 12.2. These medium-grade sources would be suitable for solid DAC and low-grade sources could be upgraded via heat pumps. Dispersed sources such as supermarkets and bakeries are unlikely to be attractive for DAC due to size and are more likely to be attractive for district heating systems. Instead, waste heat sources that are more isolated and that DAC could be incorporated with from the start or the project (as opposed to retrofitted on to) would be attractive, examples being nuclear energy, green hydrogen electrolysis and e-fuel production.

Figure 12.2: Examples of waste heat sources in Scotland identified in report for ClimateXChange looking into waste heat sources in Scotland (Building Research Establishment, 2020).

Research trends

Research trends relevant to integration with waste heat:

• Lower temperature sorbent materials: if the temperatures required for regeneration can be reduced, then waste heat can supply a larger portion of the thermal energy demand
• Modular units: while not the key driver for making DAC modular, making units small, scalable and easy to integrate with other processes would allow DAC units to take advantage of dispersed sources of waste heat

Integration with renewable energy

DAC needs clean, low-cost energy with a high load factor. Climeworks has largely deployed in Iceland due to the cheap heat and electricity provided by geothermal energy. Carbon Engineering are deploying in Texas, where there is inexpensive and plentiful renewable energy plus cheap natural gas. Locations with continuous sources of renewable energy, such as geothermal or hydro are particularly appealing, but integration with wind energy is likely to be more relevant for Scotland.

As a rule of thumb, DAC only has ‘relevant’ amounts of negative emissions if renewable energy provides 80% of the energy supplied through the grid (AGU, 2018). Scotland’s electricity grid is around 60% renewables in terms of energy used but with a lot of renewable energy being distributed to other parts of the UK (Scottish Energy Statistics Hub, 2024). Using curtailed energy is attractive for many purposes, but it is hard to make DAC economical with current capex costs if the system is only used part of the time. A 2018 report stated that either DAC capex costs would have to come down 10-fold or carbon prices go up 10-fold to make running DAC on curtailed energy viable (AGU, 2018). While running purely on curtailed energy is never likely to be economically appealing, running only when the grid is at above 80% renewables could be. This sensitivity will be investigated in the modelling phase of this study.

Research trends

Research trends relevant to integration with renewable energy:

• Lower temperature sorbent materials: if the temperatures required for regeneration can be reduced, then heat pumps are able to supply the energy more efficiently making integration with renewable energy more efficient
• Electrochemical DAC: requires only electrical energy rather than thermal energy
• Understanding local environmental impacts: maritime environments are hard on components, understanding which components are most affected and limit the life of the system is a part of the ongoing learnings from current deployments
• Energy storage: incorporating energy storage would allow for higher load factors and better use of cheaper renewable energy but would also increase the capex costs
• Tidal energy: EMEC brought forward the idea of pairing DAC with tidal energy, due to the periodic nature of tidal energy generation and the cycling nature of solid DAC, especially interesting as EMEC and Orkney are a key centre for tidal energy.

Learnings from deployment

Both Climeworks and Carbon Engineering stated that learning from deployments was their main focus for R&D and where they see the most progress coming from. Climeworks said they are adapting their testing facilities to be more ‘real-life’ and saw the main improvements coming from “better sorbents, better structuring better design of the plant”.

Climeworks posted a very open article on their website titled “The reality of deploying carbon removal via direct air capture in the field” that described and quantified many of the issues they had encountered in the first two years that the Orca plant was operating. (Climeworks, 2024) Many of these learnings were issues that caused the plant to underperform (e.g. 20% quality fluctuations in the sorbent material, recovery losses of 30% of the captured CO₂) but saw the main cost reductions being in applying lessons learned from current deployments such as adaption for local weather conditions.

Understudied areas for R&D in DAC

Three key areas of that emerged as understudied areas for DAC are

• Integration with waste heat: currently limited to an extent by a lack of information sharing between commercial parties but the opportunities may become more obvious as the technology matures and progress becomes steadier
• Impact of local conditions: with relatively few deployments in place already, the impact of local conditions is not yet fully understood. Elements of local conditions could be climatic (largely temperature and humidity) and impacts of pollution (contamination of filters, degradation of components). These will affect costs and efficiencies, but also which technologies are best suited to which environments. For example, electrochemical DAC is less mature than other DAC technologies but is attractive in Scotland because it runs purely off electricity rather than heat. Different DAC technologies will be better suited to different locations and sensitive to different parameters, research will be needed for optimisation, aided by modelling.

1. Limiting factors in DAC deployments

This section gives more detail on the key limiting factors in DAC technology and projects. Limiting factors that affect the cost and profitability of a plant but also the rate at which a DAC plant or plants could be deployed beyond purely financial limitations.

Energy demand and cost

From discussion with industry, the key limiting factor for deployment and the key factor in deciding location was cost of energy. The UK is seen as an expensive place for energy compared to the likes of Iceland or Texas where DAC is being deployed. The impact of energy costs will be a key part of the scenarios investigated in the modelling phase. The UK Green Book projects industrial electricity costs in the central scenario to go from 18 p/kWh down to 11 p/kWh over the next decade,^[11] electricity prices in Iceland are not only lower, in the region of 5­6 p/kWh but also much more consistent (Statistics Iceland, 2022; DESNZ, 2024).

In terms of the scale of the energy demand, a 0.5 Mt plant would require around 1 TWh of energy per year, based on a value of 2 MWh/tCO₂ (IEA, 2024). For context, in 2023, Scotland generated just over 33 TWh of renewable electricity; 1 TWh is roughly equivalent to energy demand of homes in Dundee (Scottish Government, 2024). The energy demand for DAC is around 20% electrical energy and 80% thermal energy. With solid DAC, that 80% thermal energy can be provided by heat pumps, bringing the overall energy demand down. Assuming a heat pump COP of 2, considering the high temperatures needed, the overall energy demand could be brought down to 0.6 TWh. If that 0.6 TWh of energy demand is assumed to be spread evenly across the year (i.e. a load factor of 1), then the connection size required for a 0.5 Mt DAC plant would be in the region of 68 MW. This 68 MW value is equivalent to other large industrial connections or a data centre.

Demand for CO₂

Interviewees generally noted that the other key factor holding back DAC deployment was a lack of long-term demand or a clear carbon market. This market can be either:

• Carbon removals/storage
• Using non-fossil carbon for application or manufacture of existing products or services, e.g. food and drinks, fertiliser
• Using non-fossil carbon for new products or services such as e-fuels or low-carbon chemicals

DAC projects selling CO₂ removals (carbon offset credits) are reliant on government policy incentives (e.g. USA’s Inflation Reduction Act), or via off-take agreements on the Voluntary Carbon Market (VCM). The VCM is composed of organisations or individuals buying carbon credits for the purposes of offsetting their emissions, this market can be volatile and is unlikely to scale to size that is meaningful in reducing global emissions due to its voluntary nature. Government mandates and regulation on removals could provide the long-term security for investors in DAC that is not offered by the VCM. The UK Government announced in its 2021 Net Zero Strategy an ambition for 5 MtCO₂ of removals by 2030 and 23 MtCO₂ by 2035, but this is not yet been backed by a mandate, and this could be met by other removal technologies than DAC (e.g. BECCS) (BEIS, 2021).

It was also noted that in jurisdictions where there are helpful policies in place, those policies often come with restrictions that all activities have to take place within the boundary of that jurisdiction. Large scale deployment will need policies that generate demand across a lot of jurisdictions and allow providers to function in an open market.

The market for captured CO₂ as a feedstock in the chemical industry appears to be very immature, with very little information available.

SAF Mandates

SAF mandates were discussed widely in the interviews with attention drawn to differences between the UK and EU SAF (ReFuelEU) mandates where the EU mandate is explicit about where the CO₂ in SAF comes from, whereas the UK mandate does not make a distinction. The expectation is that the EU mandate will phase out fossil-based CO₂ over time, for other jurisdictions there is lower confidence about if and when fossil CO₂ will be phased out. The UK has announced an intention to bring in a specific requirement for DAC within the SAF mandate in future.

Emissions Trading Scheme

The Emissions Trading Scheme (ETS) offers a mechanism for DAC to become financially attractive, especially in terms of capture and storage but only if DAC is recognised within the ETS system or the penalty price becomes comparable to the cost of DAC. The question of how greenhouse gas removal (GGR) systems should be integrated into the UK ETS system is currently being consulted on (closed 15^th August 2024). There is concern that integration of removals in the ETS scheme could reduce efforts to reduce emissions (Department for Energy Security & Net Zero, 2023). The carbon price in 2025 is around £90 (~$120), with gradual but uneven increase out to 2050. These carbon values are at the low end of projections for the cost of capture for DAC, as the carbon price increases towards a maximum of £170, (~$220), it gets closer to the potential range of DAC costs.

To incentivise emitters to pay for DAC or DACCS, the more appropriate price comparison would be the buyout price: how much organisations are charged for every tonne of carbon they emit that they do not have carbon credits for. Currently, the buyout price for CO₂ in the UK is £100/tCO₂, not much above the carbon price and far below the price that would incentivise DAC use to offset emissions (ICAP, 2022). The names of companies that exceed their emissions allowance are also published, an incentive to comply for companies with a public profile.

Figure 12.3: Projected values for the UK carbon prices used for modelling purposes (Department for Energy Security & Net Zero, 2023).

Planning restrictions

Planning restrictions relevant to DAC are largely around land use and visual impact but the time taken to get planning permission was viewed as an obstacle for DAC projects, mostly because of how long the process can take. A 0.5 Mt DAC plant would be considered a major development; the average planning time for major development projects in Scotland in 2023/24 ranged widely from 22 weeks for projects with processing agreements compared to 53 weeks for those without (Scottish Government, 2024). This difference highlights the advantage of planning agreements and working with the Scottish Government and local authorities. These planning times have been gradually coming down over the last few years and the Scottish Government was praised in some of the engagements within this study for being more dynamic and working with companies to progress projects.

Impact of delays

The cost of delays depends heavily on what stage of the project the delay occurs: a delay at the start of the project has a smaller impact than at the end of the project where there are higher running costs, e.g. staff hired, money borrowed. A very rough rule of thumb is that delays cost 1-2% of the project costs per month. Planning delays can easily run into months, even years. Taking the lower end of those delay costs, 1% per month, is 12% additional costs for a year delay.

Perhaps the most impactful element of planning restrictions is confidence: a country or region known to have a very strict, complex or slow planning process is not attractive for DAC deployment where R&D is still happening at pace, and it may be difficult to give full details of what a plant will look like at the start of the process. Focusing early DAC deployment at existing industrial sites may be helpful in terms of space, grid capacity and minimising visual impacts, as would a flexible planning process with open dialogue with decision makers.

Geographical requirements

Location

The main geographical requirements for DAC are:

• Near or connected to low cost, low carbon electricity with a high load factor
• Near transport, storage or usage of CO2

During our expert interviews, a rule of thumb was discussed for liquid DAC that if a country was a net importer of natural gas, it is unlikely to be good candidate for liquid DAC. The UK has been a net importer of gas since 2004, indicating that Scotland could be more suitable for solid DAC (Lennon, 2024). Green hydrogen could be used instead of natural gas, but it is unlikely that this would be economical or the best use of green hydrogen. These costs can be investigated in the modelling phase.

Climate

An additional geographical consideration is climate. Most deployments so far have been in Europe or North America, Climeworks have currently deployed in Iceland and Switzerland and are learning how climate impacts their process. Based on learning from those locations, Scotland becomes a more attractive location than places like the Middle East or North Africa where the processes would need to be re-optimised for the climate, especially while deployments are being developed and scaled up.

Model-based research has indicated that cold (<18°C average temperature) and dry (<65% relative humidity) climates are most ideal for DAC. The UK is classified is cold and humid, along with much of Europe and parts of North America. Cold climates, dry or humid, were found to be most favourable climate-wise for DAC but lower energy prices in hotter places (e.g. Middle East, North Africa) compensate for this. This research is based on current, or at least recent, data published on the processes and materials used for DAC and adaption of materials and processes would allow optimisation for different climates, e.g. favouring more selective sorbents in humid regions to avoid capturing water instead of CO₂ (Sendi, 2022).

Land area

The land use requirements for solid DAC plants and liquid DAC plants are very similar, 0.4 km² and 0.5 km² at a million tonne scale plant respectively (World Resources Institute, n.d.). For comparison, the land area needed for a forest to capture a megaton of CO₂ is 860 km². These values for the land use of DAC plants do not account for land area required for energy generation.

Transport and storage

Transport and storage of CO₂ has been highlighted as a limiting factor both interviews, particularly in the short term. As the DAC industry matures, transport and storage is expected to become less of an issue as transport is optimised and large-scale storage infrastructure is established. Carbon Engineering noted that a key advantage of their site in Texas is that it is placed directly above large CO₂ storage reserves. Pipelines and plans for CO₂ storage are already in development.

Currently, CO₂ is transported mainly by lorries, a limiting factor both in terms of reducing cost and achieving scale of transport and storage. This limiting factor is mirrored on the demand side for the likes of e-fuel manufacturers who will likely need onsite generation to meet CO₂ demands as they scale up.

Ambitions for CO₂ storage

The UK Government announced two sets of projects, Track-1 and Track-2 clusters, with an ambition to capture 20-30 Mt CO₂ per year (Department for Business, Energy and Industrial Strategy, 2023). The Acorn project in the North Sea is within Track-2 and is part of an ambition to capture 5­10 Mtpa CO₂ (Acorn, 2024). The Acorn project will repurpose existing gas processing and transporting facilities to permanently store CO₂ under the North Sea (Scottish Government, n.d.). The Acorn project initially had an ambition to be delivering CCS by the mid-2020s, and storing 5­6 Mtpa by 2030, but a more recent press report from mid-2024 refers to support from the Scottish Government to “make the Scottish Cluster a reality” indicating a much lower confidence level on the timeline of delivery (Acorn, 2021; Acorn, 2024).

Supply-chain requirements

Supply chain requirements and limitations were discussed with stakeholders and investigated in previous work by City Science. The most likely material to cause a potential bottleneck in the DAC supply chain is amine sorbents, the carbon capturing material in solid DAC technology (McQueen et al., 2021). The bottleneck would occur due to DAC requiring large volumes compared to current production levels as opposed to any issue with a particular material or feedstock, although there are some processing issues as exposure to the precursor chemicals is harmful. These amine-based sorbents are currently produced in small volumes mainly for pharmaceutical applications, there may need to be development of a large-scale synthesis process that could take time to optimise (Coherent Market Insight , 2023). Part of the issue with sorbents such as PEI is that it degrades through the cycles and needs to be replaced or topped up, meaning the demand is ongoing rather than just when the plant is being set up. Improvements to the longevity and alternative materials are active areas of research (Sodiq, 2022). Early engagement with the industry to understand the scale of demand could mitigate some of these issues.

Previous work City Science has carried out has highlighted that material supply of generic materials was not likely to be a limiting factor in DAC supply. The three materials main materials considered were steel, concrete and aluminium. Within the stakeholder engagements as part of this study, no organisation has specifically stated material availability as a key limiting factor in their scale up although materials were mentioned as generic issues encountered during scale up.

In terms of equipment, many components already have very mature supply chains, especially from the oil and gas industry. Some interviewees said that the small size of the DAC industry compared to these suppliers’ usual industries has taken some getting used to for supply chains. Interviewees also discussed learning from deployments where compromises could be made with respect to supply chains and materials e.g. cost versus quality and longevity.

Commercial sensitivity and maturity

A limiting factor that came out of our discussions with industry experts was commercial sensitivity and maturity. One aspect is that there are so many DAC start-ups, each with a slightly different approach or process and each protecting their own commercial interests. The variety of processes and the lack of detailed process information makes it hard for potential backers or partners to pick a technology or company. EMEC was highlighted as a major draw in Scotland and a mechanism for overcoming some of these commercial sensitivity issues due to the expertise, potential for partnerships and involvement in demonstration activities.

1. Additional details on DAC cost modelling

The cost model used in this study is based on method used by Young et al. (Young, 2023). This approach uses cost data from early-stage DAC plants and applies then projects cost reductions based on learning rates as global deployment increases. The cost model uses an initial plant, the FOAK, then applies learning rates at each doubling of global capacity.^[12]

The FOAK size used for the solid technology was 4 ktCO₂, based on the Climeworks Orca plant. The FOAK size used for the liquid technology was 500 ktCO₂ capacity, based on the STRATOS plant under construction, using Carbon Engineering technology. The FOAK cost is then projected over a level of deployment (i.e. over a number of doublings of capacity) to produce the NOAK cost.

The cost components of the ‘FOAK Outputs’ and ‘NOAK Outputs’ are then used to determine a cost of DAC, which is a levelised cost per tonne of CO₂ evaluated over the lifetime of the plant. Equation 1 below demonstrates how the NUAC is calculated.

Equation 1

The CRF is the capital recovery factor, used to calculate the payback on financing required for the plant capex. Annual capex payments are calculated by multiplying the capex by the CRF. The CRF is based on both the cost of capital (i) and the plant lifetime (n) as shown in Equation 2. The cost of capital was set at 3.5% in the central case, consistent with a social discounting rate, and a value of 10% used in the sensitivity analysis to represent a more commercial weighted average cost of capital (WACC) (UK Government, 2021; DESNZ, 2024).

Equation 2

Three types of cost of DAC can been calculated, depending on the scope of emissions accounted for, and whether costs of transportation and storage are included:

• Levelised cost of DAC (LCOD) (gross captured): NPV of abatement determined on the amount of CO₂ physically captured by the DAC plant.
• Levelised cost of removal (LCOR)NUAC (net captured): NPV of abatement determined on the amount of CO₂ physically captured by the DAC plant, minus any Scope 1 and 2 emissions, to derive a net abatement.
• Levelised cost of storage (net stored): Uses the net captured abatement. Includes the costs of transport and storage of CO₂.

It is the NUAC net captured value that has been used in this study, also called the levelised cost of removal (LCOR). This definition accounts for the CO₂ produced via scope 1 and scope 2 emissions, i.e. the emissions associated with the energy used to run the DAC plant.

A 2-year build period has been assumed for the costing (for both technologies), with the CAPEX spread equally across the first two years. There is no CO₂ capture in these first two years as the plant is not yet operational; after the two-year build period, the annual costs (energy and non-energy OPEX) are modelled for each year, as well as the CO₂ capture. The total length of the analysis period is therefore plant lifetime plus two years.

1. Range of projected SAF values

There is significant uncertainty in the projected cost of e-SAF driven by large uncertainty in several key contributing factors to the overall cost such as energy prices, the cost of green hydrogen and the cost of DAC. The Sustainable Aviation Fuel Mandate Final Stage Cost Benefit Analysis presents a range of SAF costs illustrating this uncertainty that had to be considered in setting the buyout price for SAF and e-SAF, shown in Figure 12.4 (Department for Transport, 2024b). The projected ranges for PTL, that we have referred to as e-SAF in this report, span a range of thousands of pounds, hence the focus in this study on understanding what the key factors are that will dictate where costs lie within this range.

Figure 12.4: Range of costs for various sustainable aviation fuel types presented as part of the analysis for the UK SAF mandate (Department for Transport, 2024b).

1. International Energy Data

A summary of the energy data used in the international comparison is provided in Table 12.3. The number of sources used has been minimised where possible to avoid differences in the assumptions and methods used to derive these figures. To account for the recent increase in energy prices due to a rise in global conflict, energy data from 2021 was used as this represents the most recent data unaffected by this increase.

Table 12.3: A summary of the cost and carbon of fuels used in the international comparison

1. Comparison to IEA

The International Energy Agency report on DAC provides in-depth analysis, including operating conditions and cost estimates, the LCOD is shown alongside cost estimates from our modelling in Figure 12.5. Using IEA energy prices, estimates of the cost of DAC are similar between the model used in this study and the values reported by the IEA. The IEA report does not include the deployment year within the modelling assumptions however the IEA cost of DAC falls within the range of 2040 to 2050 cost estimates.

Figure 12.5: Comparison to IEA estimates of the cost of solid and liquid DAC

1. Waste Heat

Hydrogen Production via Electrolysis

Hydrogen production operates at temperatures ranging from 60°C-80°C (Koumparakis, 2025) Assuming a heat exchanger with an approach temperature of 10°C is used, the waste heat can provide heating up to 70°C.

The solid DAC reference scenario used heat pump with a coefficient of performance (COP) of 2 to provide heating up to 100°C. With the hydrogen electrolysis process providing heating up to 70°C, manufacturing tables for heat pumps estimate a heat pump operating between 70°C – 90°C (i.e. a delta T of 20°C) would perform with a COP of 4.4 (Sabroe, 2023). A conservative COP of 4 has been used for the purposes of this modelling. The use of waste heat and a high performing heat pump has significantly reduced the LCOD by 26%.

The liquid DAC reference scenario used natural gas as the heating fuel. Using waste heat supplied at 70°C, natural gas would still need to be used to provide heating from 70°C – 850°C. As a result, the benefits are small, only reducing the LCOD by 2%. It is also unclear how the waste heat could be provided in practice for a liquid DAC system.

The supply the waste heat demand for a 0.5 Mt DAC plant, the scale of the hydrogen electrolysis plant needed was estimated at 34 kt/year for solid DAC and 3 kt/year for liquid DAC, with calculations shown in Table 12.4. This assumes a heat loss from the hydrogen electrolysis process of 26% (Mostafa El-Shafie, 2023) and an electricity use of 54 kWh/kg hydrogen. The scale of the hydrogen plant is small relative to the energy demands of Scotland, 34kt of hydrogen capacity could supply 1% of Scotland’s total energy demand, or 3% of the transport sector’s energy demand (Scottish Government, 2024).

Table 12.4: Estimating the size of hydrogen electrolysis plant needed to provide the thermal energy of the DAC process.

Energy from Waste

Energy from waste (EfW) incinerators burn waste at high temperatures, generating electricity from the exhaust gases produced, a simple process flow diagram is shown in Figure 12.6. Integrating the EfW process with either solid or liquid DAC requires the diversion of heat from electricity production to the DAC process, the simplest configuration of which is also shown in Figure 12.6. Using heat directly rather than for electricity is significantly more efficient, ranging from 500 – 800% (Z factor 5 – 8). (Triple Point Heat Networks, 2024)

Figure 12.6: An example configuration of how a DAC process may utilise heat from an energy from waste process.

An energy balance of the thermal energy required from the EfW process, and the corresponding loss of power production is shown in Table 12.5. Across Scotland municipal waste EfW facilities range from 10 – 45 MW but are typically 10-15 MW. If a 0.5 Mt DAC process were to have all thermal energy requirements supplied by an EfW this would significantly reduce power production. However, this would not be viable as part of a typical EfW commercial model and has not been included as a potential waste heat source.

Table 12.5: Estimating the size of EfW plant needed to provide the thermal energy of the DAC process.

1. E-fuel production

Further detail on e-fuel production

E-fuel production via the Fisher-Tropsch (FT) Process

This section provides some additional insight into the products from the FT process and the relative amounts of each produced. The reaction typically operates at temperatures ranging from 200-240°C, and requires a metal catalyst (Speight, 2016). The type of catalyst used will lead to selectivity towards different products. This means that the reaction can be tuned to favour specific hydrocarbon fractions, i.e. short chain hydrocarbons C₁ to C₅ through to much longer oils and waxes, C₂₅+, as demonstrated in Figure 12.8. When optimised for synthetic sustainable aviation fuel (e-SAF), the kerosene portion can account for 60% of the output as demonstrated in Figure 12.7 (Wentrup, 2022). Figure 12.8 shows some percentage breakdowns for reported processes.

Figure 12.67: Illustrative figure of outputs from the Fischer-Tropsch process, showing the relative amounts of different lengths of hydrocarbons created. (Bharti, 2021)

Figure 12.812.7: Percentage outputs of hydrocarbons for various FT processes (Fasihi, 2016).

The FT process is energy-intensive, with significant heat generation. The waste heat from FT synthesis can be utilised to support DAC operations. Assuming a heat exchanger with an approach temperature of 10°C, the available heat can provide heating up to 230°C, meeting 100% of the thermal energy requirements for solid DAC and 25% for liquid DAC. Table 12.6 shows that the estimated e-fuel production scale required to satisfy this waste heat demand is 583 kt for solid DAC and 144 kt for liquid DAC, assuming a heat loss of 1.29 MWh per tonne of e-fuel (Marchese, 2020).

Table 12.6: Estimating the size of E-fuel plant needed to provide the thermal energy of the DAC process.

Key assumptions for the Fisher-Tropsch process within this study are given in Table 12.7.

Table 12.7: Key assumptions for e-fuel production in this study.

Uncertainty in e-fuel production costs

This section gives an overview of some of the uncertainties in e-fuel production costs from key sources for this report.

The cost of e-fuel production is dependent on four key variables:

• Cost of electricity
• Cost of green hydrogen
• Cost of CO₂
• Cost of e-fuel equipment capex

The future cost of all four of these key variables are highly uncertain. Research by Rojas-Michaga et al. models the contributing factors to e-fuel production cost and the associated uncertainties. Figure 12.9 shows the results of a simulation investigating the potential combinations of factors illustrating the range of potential costs. The modelling outputs form a bell curve showing the likely range of fuel costs in £/kg; the 95% confidence range is between £2.44/kg and £12.91/kg range. The buyout price for PtL in the UK SAF mandate is set at £5/litre, £6.25/kg which is just to the low side of the peak in Figure 12.9. This buyout price will need to be reviewed over time alongside the required percentage of PtL fuel in UK demand.

Figure 12.9: Uncertainty analysis of e-fuel costs showing the potential range of e-fuel costs in £/kg (Rojas-Michaga, 2023).

Impact of CO₂ costs

The biggest contribution to uncertainty in e-fuel costs is expected to be the cost of hydrogen, both because hydrogen is one of the biggest contributions to the overall cost and because the future cost of hydrogen is very uncertain (ClimateXChange, 2023; Rojas-Michaga, 2023). The two other biggest sensitivities are the cost of electricity and the cost of CO₂ in the form of DAC. Figure 12.10 (from the same paper as Figure 12.9) shows a sensitivity analysis of key metrics on the cost of a tonne of e-fuel.

Figure 12.10 : Sensitivity of e-fuel price to changes in costs of key variables (MJSP = minimum jet fuel selling price) (Rojas-Michaga, 2023).

The values used in the sensitivity analysis are given in Table 12.85 (Rojas-Michaga, 2023) Their analysis gives a cost breakdown of around 30% CO₂, 60% H₂ and 10% for the remaining costs. This CO₂ contribution is much higher than some others due to the assumption that the CO₂ is from DAC. In a fuel cost of £5/litre, non-CO₂ costs are around £3.5/litre, equivalent to £4,375/tonne of e-fuel. These values were used investigate the likely range of e-fuel prices in section 12.1.22 below.

Table 12.85: Values used in sensitivity analysis in research by Rojas-Michaga et. al (Rojas-Michaga, 2023).

UK SAF mandate buyout price

Figure 12.11 shows the projected costs for different fuels including PtL from DAC (Department for Transport, 2024b). The calculations project values for e-SAF made using DAC in the central case to be around £4k/t but with best and worst case scenarios of £2.2k/t to £9.1k/t.

Figure 12.11 : Table brought in from analysis as part of developing the UK SAF mandate showing the projected costs for different fuels including PtL from DAC (Department for Transport, 2024b).

UK and EU SAF Mandates

The UK’s Jet Zero strategy sets out the UK Government’s strategy to decarbonise air travel, to be introduced from 1 January 2025, sets out targets for requirements for the use of SAF and e-SAF for the UK aviation sector. (Department for Transport, 2024a) In 2025, 2% of UK jet fuel demand will be required to come from sustainable sources, increasing linearly to 10% in 2030, then to 22% in 2040.^[13] The mandate for e-SAF starts in 2028, reaching 0.5% in 2030 and 3.5% in 2040. For context, the last reported UK energy demands were 2022, when UK aviation fuel demands were around 12 Mtoe, though expected to increase in the short term in the rebound from the pandemic. (Office for National Statistics, 2024) The SAF mandate states there is potential to increase these target percentages if market conditions allow.

The equivalent mandate for the EU, ReFuelEU Aviation, has a less ambitious early timeline, but the ramping of targets is steeper and the EU mandate is more specific about CO₂ sources. The EU mandate targets 2% SAF by 2025 and only 6% by 2030 but the ramping is steeper with a 20% target by 2035 and a 70% target by 2050. (European Commission, 2023; International Trade Administration, 2024) For synthetic fuels, the EU mandate aims for 1.2% in all EU airports from 2030 (equivalent to around 0.7-0.9 Mt), more than double the UK percentage for the same year, and 35% synthetic fuels in all EU airports from 2050. (Green Air, 2025) The EU mandate is also explicit about the source of CO₂ for synthetic fuels removing the option to use fossil-generated CO₂ to make e-fuels from 2041, allowing only biogenic and DAC CO₂, accepting these are the only sources compatible with future climate neutrality.

The UK SAF mandate states that the feedstock for PtL fuels will be DAC or point source carbon (biogenic or fossil fuel) but it is not clear if there are restrictions to be placed on what point sources would be allowed. The mandate does state that waste fossil CO₂ is considered to “have zero lifecycle greenhouse gas emissions up to the point of collection”. (Department for Transport, 2024b, p. 86) The UK mandate recognises that DAC will be the main CO₂ source in the long term but that it is expensive in the short term and they do not want to hinder early development. Recognition that DAC will need to be the main source of CO₂ for PtLs in the long-term is reflected in the buyout price, which has been set based on projected DAC-based PtL costs.

E-fuels for shipping

A 2019 report by Lloyd’s Register and UMAS set out a number of scenarios of the potential future mix of low-carbon shipping fuels: a renewables dominated pathway; a bioenergy dominated pathway, and a mixed pathway. The mixed pathway, shown in Figure 12.812, has been used in the modelling in this study as a central scenario for potential e-fuel demands. Figure 12.13 shows the projected mix of e-fuel for shipping from Transport & Environment’ briefing used to estimate the proportion of carbon-based shipping fuels in future years. (Transport & Environment, 2024)

Figure 12.812: Figure taken from Lloyd’s Register and UMAS report showing projected fuel mix for shipping each decade to 2050 in the equal mix pathway. (Lloyd’s Register, UMAS, 2021)

Figure 12.13: Projected mix of e-fuel for shipping from Transport & Environment’ briefing “E-Fuels observatory for shipping” 2024. (Transport & Environment, 2024)

How to cite this publication:

McQuillen, J., Goodwin, H., Kennedy, E., Li, L. (2025) ‘Cost and profitability of direct air capture in Scotland’, ClimateXChange. http://dx.doi.org/10.7488/era/5940

© The University of Edinburgh, 2025
Prepared by City Science 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

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

1. 
   

   For context, the total carbon removal market (carbon removals, as opposed to generic carbon offsets) totalled around 13 MtCO₂ globally by the end of 2024 (cdr.fyi, 2024). ↑

   
   
2. 
   

   Green Book values for future energy costs are generally used for modelling exercises in studies such as this but there is a lack of confidence in projected energy costs, particularly given volatility in recent years. Therefore, Green Book costs were used as a sensitivity rather than as the central case. ↑

   
   
3. 
   

   Upstream gas emissions are very difficult to accurate quantify, this uncertainty around quantification limits the confidence in the LCOR of liquid DAC(Cooper, et al., 2022). ↑

   
   
4. 
   

   This estimation is based on the assumption that 10% of the total planted area utilises enriched CO₂ with a rate of 5-10% across the industry (Ecofys, 2017). ↑

   
   
5. 
   

   In terms of hydrogen production, only green hydrogen makes sense for the production of e-fuels as blue hydrogen would involve splitting methane for the chemical constituents only to recombine them to remake hydrocarbons. ↑

   
   
6. 
   

   Currently, eligible SAF must be produced from sustainable waste or residue feedstocks, such as used cooking oil, forestry residues, unrecyclable plastics, or derived from renewable or nuclear power. Fuels produced from food, feed, or energy crops are not eligible. Over time, the portion of SAF that can come from certain sources (such as cooking oil) will be reduced. ↑

   
   
7. 
   

   The targets within the EU SAF mandate for CO₂ from DAC are 10% of the carbon feedstock in 2030, 20% in 2035, 40% in 2040, 80% in 2045 and 100% by 2050. ↑

   
   
8. 
   

   This 20% premium on production costs would presumably cover interest on financing used plus profit for DAC, e-fuel production and green hydrogen production. ↑

   
   
9. 
   

   The relevant figures from the Lloyds Register & UMAS report and the Transport & Environment report are shown in Appendix I section 12.1.23 (Figure 12.812 and Figure 12.13) (Lloyd’s Register, UMAS, 2021). ↑

   
   
10. 
    

    In discussion with industry experts, the issue of regulation around repurposing waste products was raised. Recycling products assigned as waste into marketable products creates issues around certification. Making this process of waste to product easier would require the reduction of regulatory barriers across the recycled aggregates industry. ↑

    
    
11. 
    

    In the high scenario, costs reach up to 40 p/kWh before coming down to 13 p/kWh over the next decade to 2034; in the low scenario drop down much more quickly and are in the range 10-13 p/kWh to 2034. ↑

    
    
12. 
    

    This application of learning rates to every doubling of technology is an observed trend of developing technologies, sometimes referred to as Wright’s Law. ↑

    
    
13. 
    

    Currently, eligible SAF must be produced from sustainable waste or residue feedstocks, such as used cooking oil, forestry residues, unrecyclable plastics, or derived from renewable or nuclear power. Fuels produced from food, feed, or energy crops are not eligible. Over time, the portion of SAF that can come from certain sources (such as cooking oil) will be reduced. ↑

    
    

Scotland has legally binding targets to achieve net zero greenhouse gas emissions by 2045. Non-domestic buildings account for around 6% of Scotland’s total greenhouse gas emissions.

This report explores the impact of policy proposals consulted on in the Heat in Buildings Bill to require non-domestic buildings to end their use of polluting heating after purchase by 2045 or before.

The research examines Scotland’s non-domestic property market, the proportion of different building types and types of leases. This is supplemented by a review of comparable policies across Europe impacting non-domestic property leases.

Key findings

The non-domestic property market and its stakeholders in Scotland are hugely varied. As of June 2024, there are around 247,000 non-domestic properties in Scotland, with offices, factories and warehouses, and retail units making up a large proportion of these buildings.

This research highlights the complex arrangements within the non-domestic market and the difficultly in making major changes to these buildings, such as upgrading the heating system to a heat pump or connecting to a heat network. The most significant impact would be on landlords and tenants but there is a risk of impact in the wider market, including on non-domestic property prices and abandoned buildings.

Retrofit challenges

Some non-domestic buildings have already been retrofitted to achieve higher energy efficiency. The proportion of these buildings is small and insufficient to meet decarbonisation targets. Many businesses may want to decarbonise their buildings but would not know how to do so.

Lease arrangements: landlord and tenant(s) obligations

There was a lot of uncertainty and mixed responses on how cost and disruption would be managed by landlords and tenants. The impact will depend both on how the legislation is drafted and the specific clauses in each contract. It will also depend on the cost and complexity of the upgrade needed to meet the requirements.

Upgrade date

Having a requirement to upgrade all buildings by a certain date would be easier for stakeholders to comply with than a point of sale trigger. A requirement to upgrade after the sale of the property could have a particularly detrimental impact on tenants if the cost or disruption of upgrades is passed onto them.

Industry engagement

The non-domestic market is complex and cannot be easily compared to the domestic market in the design of policies. The design of the policy would benefit from close engagement with industry to minimise impacts on non-domestic building stakeholders and the market.

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: September 2024

DOI: http://dx.doi.org/10.7488/era/5039

Executive summary

This report explores the impact of policy proposals to require non-domestic buildings to end their use of polluting heating by 2045, or before that, after being bought. These were included in the consultation on proposals for a Heat in Buildings Bill.

The point of sale trigger proposal would require property buyers to replace their polluting heating system with an alternative clean heating system, such as a heat pump, within a grace period, after purchasing a property.

These measures intend to give confidence to the market in demand for clean heating systems and support a smooth transition whereby homeowners, landlords and businesses switch heating systems at an appropriate and practical time, rather than waiting until 2045.

This project also explores the impact of proposals to introduce a requirement to upgrade heating systems in non-domestic properties at the point of property sale, or by 2045, on lease arrangements in Scotland. It explores how the proposed policies will interact with the operation of non-domestic lease arrangements in Scotland, the varying impacts of different timescales of the leases and the impact on the non-domestic property market. It also considers how existing lease arrangements could impact the ability of non-domestic buildings to comply with the policy proposals.

We conducted research on Scotland’s non-domestic property market and the proportion of different building types (e.g. offices, retail). We also explored the different types of leases and their key characteristics. This was supplemented by a review of comparable policies across Europe impacting non-domestic property leases.

These methods enabled us to assess the impact on key stakeholders, primarily landlords and tenants, with different lease arrangements. Interviews with a small sample of experts, including commercial lawyers and real estate investment companies, provided valuable insights.

Key findings

The non-domestic property market and its stakeholders in Scotland are hugely varied. As of June 2024, there are around 247,000 non-domestic properties in Scotland, with offices, factories and warehouses, and retail units making up a large proportion of these buildings.

This research highlighted the complex arrangements within the non-domestic market and the difficultly in making major changes to these buildings, such as upgrading the heating system to a heat pump or connecting to a heat network. The most significant impact would be on landlords and tenants but there is a risk of impact in the wider market, including on non-domestic property prices and abandoned buildings.

Retrofit challenges

Some non-domestic buildings have already been retrofitted to achieve higher energy efficiency. However, the proportion of these buildings is small and insufficient to meet decarbonisation targets. One interviewee commented that many businesses, particularly smaller businesses, may want to decarbonise their buildings but would not know how to do so.

Lease arrangements: landlord and tenant(s) obligations

The most common lease arrangement in Scotland is a full repairing and insurance (FRI) lease. There are some similarities in the FRI leases in different buildings but it is the clauses in each lease that determine exactly how both the building landlord and the tenant(s) are impacted if a new requirement is introduced. These clauses vary depending on factors such as the type, size and priorities of the business owning and using the building.

Through an FRI lease the aim for the landlord is to transfer any responsibility for repairing, maintaining and insuring the property onto the tenant(s). The aim of the tenant is to minimise their responsibility to pay or face disruption for repairing, maintaining and insuring the property. Where a heating system is not broken and does not fall under a repair obligation, but needs to be improved or upgraded, there would be an interest for both parties to reduce the proportion of the cost they have to pay.

Similarly, whilst less common, internal repairing (IR) leases will aim to have clear responsibility for tenant space and common building space, with both landlords and tenants wanting to minimise their responsibility.

There was a lot of uncertainty and mixed responses in our interviews with industry stakeholders, including law firms, real estate services and investment companies, on how this cost and disruption would be managed by landlords and tenants. The impact will depend both on how the legislation is drafted and the specific clauses in each contract. It will also depend on the cost and complexity of the upgrade needed to meet the requirements.

There will be complexity in all situations where the non-domestic building requires a major retrofit to comply, but the requirement becomes more challenging when it is a multi-let building (e.g. an office block with multiple different businesses occupying different parts of the building or a building used for both domestic and non-domestic purposes). In multi-let buildings, tenants usually pay a ‘service charge’ to cover costs for common parts of the building, e.g. building management services or building upkeep. In a multi-let building, it is likely that all the leases will end at different points, so there is unlikely to be an obvious trigger point when the building is empty.

Upgrade date

Most interviewees observed that having a backstop date, i.e. a requirement to upgrade all buildings by a certain date, would be easier for stakeholders to comply with than a point of sale trigger. A requirement to upgrade after the sale of the property could have a particularly detrimental impact on tenants if the cost or disruption of upgrades is passed onto them, either through a service charge or increased rent. Tenants would likely have limited or no foresight on the building being sold and would therefore not be able to build any additional costs into their business plan.

Industry engagement

The Minimum Energy Efficiency Standard in England and Wales has demonstrated that there can be a lot of uncertainty around the roles and responsibilities on complying with comparable policies. The non-domestic market is complex and cannot be easily compared to the domestic market in the design of policies.

The design of the policy would benefit from close engagement with industry to minimise impacts on non-domestic building stakeholders and the market.

Glossary / Abbreviations table

Introduction

Policy context

Scotland has legally binding targets to achieve ‘net zero’ greenhouse gas emissions by 2045. Currently non-domestic buildings accounting for around 6% of Scotland’s total greenhouse gas emissions.

Following the publication of the Heat in Buildings Strategy in 2021, the Scottish Government published the ‘Delivering net zero for Scotland’s buildings – Heat in Buildings Bill: consultation’ in November 2023. Within this consultation there was a proposal to introduce a new law which will prohibit the use of polluting heating from 2045 and require those purchasing a property to comply with the prohibition on polluting heating within a specified amount of time following completion of the sale.

Under this proposed law, a ban will apply to the use of all polluting heating systems from 2045, in line with the 2021 Heat in Buildings Strategy. The consultation also asked for views on a property purchase trigger. Under this proposed law, the purchaser of a property will be given time (a grace period) to have the work carried out, including time to have their building assessed and / or to receive quotes from installers as necessary. The consultation sought views on the length of time the grace period should last for both domestic and non-domestic properties, proposing between 2-5 years. This is intended to balance the need to treat the new building owner fairly with the need to make progress in reducing emissions.​ There was also a question in the consultation on whether to apply the requirements to all commercial long-term leases registered with the Registers of Scotland in addition to sales of non-domestic properties.

Current progress towards decarbonising non-domestic buildings

Most interviewees observed that the non-domestic building market is already transitioning to low carbon solutions or that there is an interest from businesses to decarbonise their buildings. There is a growing trend for companies to focus more on their Environmental, Social and Governance (ESG) commitments, and consequently seek out energy efficient workspace (UK Green Building Council, 2024b). In addition, recent energy price spikes have caused businesses to be more aware of their energy consumption and identify ways to reduce it (Federation of Small Businesses, 2023).

Some interviewees observed that there have been increasing examples of commercial retrofits taking place in Scotland to improve energy efficiency. For example, an office space at 4-5 Lochside Avenue, Edinburgh Park provides a good example of retrofitting an existing commercial building to an EPC B+. In this case, Knight Property Group took the decision not to demolish the original building but to comprehensively remodel, develop and refurbish the building instead. They replaced the gas-fired boilers with an efficient electric heating system and aligned to Net Zero targets and the anticipated Scottish Government ‘New Build Heat Standard’. The upgrades allowed the building to then be marketed as a ‘high quality office space in an all-electric facility aligned to net zero policies’ (UK Green Building Council, 2022). The strong environmental credentials were reported as being a key attraction for the new tenants who took on a 10-year lease (The Edinburgh Reporter, 2023).

It is recognised by industry representatives that commercial buildings are not being retrofitted at the scale needed to achieve decarbonisation targets (UK Green Building Council, 2024a). Larger organisations, such as investment companies, are likely to have already started decarbonising their buildings either in anticipation of future requirements or due to a demand from tenants for greener buildings. However, the lack of clarity around targets and support is causing delay or hesitancy among smaller, less strategic investors or owners (UK Green Building Council, 2024b). One interviewee, a large real estate investment company, stated they ‘have already started decarbonising our building stock and have noticed this happening much more in the market over the last 8-10 years but smaller landlords are less likely to be doing this’. The HiB policy proposals aim to give confidence to the market in the demand for clean heating systems, including organisations who may not currently have plans to decarbonise their buildings.

In England and Wales, data published by the Department of Energy Security and Net Zero (DESNZ) has shown that there has been some decrease in energy consumption on non-domestic buildings, but the pace of change is slow (DESNZ, 2024). Between 2012 and 2022 there has been largely stable gas consumption, except for a drop in 2020 due to Covid disruption and slightly reduced electricity consumption. In Scotland, electricity consumption in the non-domestic sector has remained relatively stable, with only a 0.1% increase from 2020 to 2021, while gas consumption decreased by 2.5% during the same period (Energy and Climate Change Directorate, 2022). Furthermore, in England and Wales, the top energy consuming sectors have been identified as offices, retail, industrial, health and hospitals, which jointly account for 71% of non-domestic energy consumption ( (UK Green Building Council, 2022).

Research aims and scope

Project scope and aim

ClimateXChange commissioned LCP Delta to undertake research into the impact of proposed clean heat regulations on non-domestic property leases, focusing on:

• How the proposed policies interact with operation of non-domestic lease agreement types in Scotland.
• The varying impacts of different timescales on leases, i.e. requirements to upgrade before the backstop or sooner due to a property purchase trigger.
• Comparable policy changes that have previously been introduced in the non-domestic property market, and lessons from the implementation and review of these policies.
• How duties and burdens are likely to fall on different parties in the sector.

Approach

The project was split into five key stages:

• Desk-based research on Scotland’s non-domestic property market to provide a base understanding of Scotland’s non-domestic property market. This also included research on the key lease types used in Scotland.
• Investigation into similar property mechanisms across Europe. We used LCP Delta’s existing heat policy database and additional desk-based research to identify comparable policies impacting non-domestic property leases.
• Development of an analytical framework to provide a systematic and robust qualitative assessment of the impact of the HiB Bill proposals on non-domestic lease agreements and market actors.
• Interviews with industry experts to input on the analysis of the impact of HiB Bill proposals on different lease types.
• Interviews with industry experts to explore the impact on wider market dynamics, for example property prices and turnover rates.

This report sets out the findings from this research which was conducted between July-September 2024.

Interview approach

We caried out eight interviews for this project with a range of experts on Scotland’s non-domestic property market. The aim of these interviews was:

• To validate our analysis on different lease types and the impact on key stakeholders, and
• To capture expert views on the impact on wider market dynamics, for example property prices.

Stakeholders were identified using desk-based research and using Scottish Government and LCP Delta networks and market knowledge. Stakeholders were selected based on their expertise on the Scottish non-domestic property market. We focused on both law firms and real estate services and investment companies due to their expertise on lease arrangements and the process of upgrading non-domestic buildings. The companies interviewed were:

• Two law firms
• Three real estate services and investment companies (one of these organisations we interviewed twice to get their views in the early stages and to test our analysis with them)
• Registers of Scotland
• Federation of Small Businesses

We started each interview with an overview of the policy and the aim of the project and provided key definitions (e.g. polluting heating system) to ensure clarity on what was being discussed. A discussion guide was developed ahead of the interviews, with questions including:

• Could you provide any insights into the structure of Scotland’s non-domestic property market? E.g. size of the market, shape of the market (e.g. type of non-domestic buildings) 
• How do you see the impacts changing if the grace period was 2 years vs 5 years?

The interviews were interviewee led, with some flexibility to allow interviewees to discuss what they considered to be the key points. Two project team members were present in each interview, with one leading the discussion and one taking minutes.

Research limitations

As this project was a broad, desk-based study the project team focused on ensuring relevant policies from other countries were identified that provided a range of learnings. It was not possible within the timeframe to investigate each of these policies extensively. A more detailed analysis or engagement with policymakers could be undertaken to understand the lessons learned from each policy in more details.

The small sample of eight interviews provided valuable insights from experts that would be directly impacted by, or are working with key stakeholders that would be impacted by, the HiB Bill policy proposals. This allowed an analysis of the likely impacts to be made for a set of broad scenarios. Further analysis and engagement with stakeholders would be required to understand more specific impacts, a more detailed understanding of the impact on different stakeholders, lease arrangements and building types. As suggested by two interviewees, this could be in the format of a series of trials where a few geographical areas are chosen to understand the lease arrangements in place and the impact if the policies were introduced.

Overview of Scotland’s non-domestic property market and lease arrangements

Scotland’s non-domestic buildings are extremely varied, ranging from new office blocks in Edinburgh, to small guest houses on the Isle of Mull and large retail units in Perth. Any policy introducing new requirements on these buildings will therefore need to consider the size and diverse nature of the building stock and its stakeholders.

The Scottish Government’s Non-Domestic Analytics dataset indicates that there are about 247,000 non-domestic properties in Scotland as of July 2024. This figure was derived based on combination of input from OS AddressBase, Scottish Assessors, and Energy Performance Certificate (EPC) records. Where data for specific properties was unavailable, the Energy Savings Trust modelled the information. The model uses Energy Savings Trust’s in-house tool and accounts for a significant proportion of the non-domestic property data (Scottish Government, 2024).

We then sought to determine the number of non-domestic leases using publicly available data, including by engaging with stakeholders such as the Registers of Scotland (ROS). From our engagement with ROS, it was noted that no publicly available dataset provides detailed and accurate information on the number and types of non-domestic leases. However, ROS experts highlighted that real-time statistics on non-domestic properties are tracked by Scottish Assessors and can be accessed publicly via the Scottish Assessors Valuation Roll. For context, the Non-Domestic Analytics dataset also uses data from Scottish Assessors data as an input. Scottish Assessors is an association of independent public officials who compile valuation rolls that list details of buildings and other property in their respective areas (Scotland’s People, n.d.). The valuation roll is a public document that includes entries for all non-domestic properties in each of Scotland’s 32 local councils, except those specifically excluded by law (Scottish Assessors, n.d.). New properties are added to the valuation roll when they are built or occupied and are removed when, for example, they are demolished. The valuation roll serves as the basis for the administration of valuation, council tax, and electoral registration services.

Recent statistics retrieved from the Scottish Assessors Valuation Roll on 9 August2024 report a total of 262,024 non-domestic properties in Scotland (Scottish Assessors, 2024). This figure still includes non-heating properties, such as quarries and monuments. When excluding these non-heating properties, we estimate that around 245,000 non-domestic properties in Scotland require heating per this database. See Appendix A for details on how this value was derived.

Figure 1 presents a comparison of the total number of non-domestic properties in Scotland, categorised by property type, based on the Scottish Government’s Non-Domestic Analytics dataset, with LCP Delta’s estimate derived from the Scottish Assessors Valuation Roll. Both datasets show a comparable total number of non-domestic properties, with only a 0.8% difference. It’s important to note that the two datasets use different property type classifications, and no effort was made to harmonise these classifications. Therefore, both datasets could be used as a valid basis for future work. If a more detailed breakdown by property type is required—for example, to ensure that impact assessments for the Heat in Buildings Bill cover as many property types as possible—the standalone Scottish Assessors dataset can be utilised.

Commercial leases in Scotland

A commercial lease is a contract between a landlord and a business tenant. The lease grants the tenant the right to use the property for a commercial purpose over a set period for an agreed rent. The lease will also outline the rights and responsibilities of the landlord and the tenant during this period.

The clauses in commercial leases in Scotland are not standardised. As such, terms and obligations vary significantly across contracts. In England and Wales Landlord and Tenant legislation governs commercial property leases, which aims to protect the rights and interests of tenants (Shepherd Wedderburn, 2019). Alongside this, there is a ‘Code for Leasing Business Premises’ which is a partially voluntary code, developed by the Royal Institution of Chartered Surveyors (RICS) as a professional standard, setting out what are considered to be fair terms that should be offered to tenants. This does not apply in Scotland and there is more limited legislative protection for commercial tenants in Scotland.

For years, commercial property solicitors in Scotland have sought a standard form of commercial lease that would bring a degree of clarity and unification to the complex area of commercial leasing. The Property Standardisation Group (PSG) was formed in 2001 to create more standardisation for documents and procedures in Scottish commercial property transactions. Whilst the PSG provides standard templates for contracts, one interviewee (a law firm representative) acknowledged that many contracts still will not follow this approach since there is no obligation to do so. If there are already leases in place it is likely parties would continue to use that format and even if they start with the PSG format it is likely there will be negotiations to change certain clauses.

Types of leases

We carried out desk-based research to identify the key lease types used in non-domestic properties. Landlord and tenant law, and lease arrangements, has been an under-researched area of Scots law (Norbash, 2022). Most interviewees commented on the complicated and varied nature of commercial leases with one stating ‘every lease is different and there is no standard’. Through our research we have identified two key categories of lease for commercial properties in Scotland:

• Full repairing and insurance lease
• Internal repairing lease

Within each of these lease types there will be a lot of variety in the clauses used within them. However, we’ve provided an overview of the key criteria of each below.

Full repairing and insurance leases (FRI) were reported to be the most common form of commercial property lease in Scotland by interviewees and industry reporting (Murray Beith Murray LLP, 2021). An FRI is used in scenarios where the tenant utilises the full building and is also common in multi-let buildings. Through this lease landlords aim to transfer their landlord’s common law responsibility of repairing, maintaining and insuring the property on to the tenant (Edwards, 2007). The tenant, on the other hand, will want to try and minimise their repair obligations under the lease as much as possible.

Ahead of entering the contract there will be negotiations on the clauses in the contract around the rights and obligation of the tenant. Tenants will usually aim to avoid having clauses in the contract which allow the cost of, for example, a new heating system to be transferred onto them or to allow a major upgrade which causes significant disruption to their business. If the existing heating system is not broken and needs upgrading to comply with new requirements it is likely this would not fall under a ‘repair’ obligation on the tenant. Tenants will usually seek to have a clause to remove the ability of the landlord to put improvement costs into the service charge. (Pitt & Noor, 2009) observed that ‘a well-drafted service charge provision in the lease is a crucial element that needs special attention by the tenant to avoid future disputes with the landlord. Where this is not in place, or the terms in each contract with the tenants vary, it will become very complicated. There are different approaches landlords can take to apportioning the service charge among tenants. These include based on floor area occupied by the tenant or a fixed percentage. One interviewee stated that ‘service charge regimes will be different for every tenant. Tenants may have something they’re willing to pay for as a tenant and fought hard for that’.

In multi-let buildings, such as office blocks, the dynamics of FRI leases can vary between tenants. FRI arrangements in multi-let buildings can be referred to as Effective Full Repairing and Insuring Lease (Effective FRI). Usually, the landlord is responsible for repairing the structure of the building and common areas and they will pass on costs back to the tenant through the service charge (Noor and Pitt, 2009). The tenant will be responsible for arranging maintenance and repairs to the internal elements of their part of the building. In these multi-let buildings it is important to both the landlord and the tenant that the description of the premise in the lease is clear, with clear obligations around different elements such as the floors and walls. In the event that repair or improvements are required to the structural elements of the building, such as the roof or the lift in a communal area, the landlords may be able to recover the costs though the service charge, depending on the clauses in the contract.

Internal repairing leases (IR) are less common within commercial property and most new leases will be FRI. These IR leases will mean that the tenant is only responsible for the upkeep and repairs to the internal elements of their part of the building (Vickery Holman, 2024). IR leases can be used in multi-let buildings (e.g. an office block with multiple different companies / tenants in separate offices). With these leases the tenant will have a narrower liability for maintenance, decorations, repairs and insurance limited to the internal parts of the property they occupy.

For all these lease types, the clauses in the contract are key to understanding obligations around repair and improvements, and there will be negotiations on the rights to enter, make changes and cover costs through the service charge. Many tenants aim to remove the landlord’s ability to make changes to their premise that cause disruption to their business or be charged for these changes through the service charge. Tenants will usually employ service charge consultants to negotiate these terms for them.

In a multi-let building it is likely that there will be differing contract arrangements for the different tenants in the building. For example, it is likely that larger organisations will have stronger bargaining power to negotiate the clauses, and therefore more likely to be able to remove clauses to pass the obligation or cost of heating upgrades onto them. A smaller organisation may have less bargaining power to do so.

Different businesses will also have different priorities in the negotiations so while some may accept certain clauses in a contract others may put a lot of work in to negotiating the clause out of the contract. For example, a tenant taking on a longer lease (e.g. 15-20 years) is more likely to accept some obligation or cost for new heating systems as they will experience more benefit from it. A tenant taking on a shorter contract (e.g. 5 years) is much less likely to accept paying for a new system.

The aim of any non-domestic lease contract is to have every element of the building covered by either a tenant or landlord responsibility. However, in practice, when an obligation comes onto the building there may be uncertainty around whose responsibility it is due to vagueness in the contract. Where there is vagueness in the contract leading to uncertainty over whether it is the landlord or tenants’ responsibility to take on the burden / cost of changes to the property, it can be a challenging situation and legal disputes can follow. Interviewees cited examples in which the responsibility over the air conditioning and its different components (e.g. plant, vents etc.) has been unclear from the contract, resulting in challenging negotiations between landlords and tenants.

Lease duration

There has been a trend of contracts getting shorter and this has been accelerated by companies exercising more caution after Covid. Most interviewees commented on this point with one law firm representative stating “leases today are generally quite short, I haven’t seen any more than ten years for a while”. It used to be fairly common to have 25-year leases but today most leases are much shorter (Garrity & Richardson, 2019). Some interviewees stated that they haven’t seen anything longer than a 10-year lease in many years and it is likely that a 10-year contract would have a break clause of 5 years. Lease length may also depend on the type of building, with offices tending to have shorter leases and industrial or warehousing leases being longer, to reflect that tenants are less likely to move on quickly (Birketts, 2021). One interviewee commented that longer leases do exist, citing one recent example they had seen of a 35-year lease.

This is an important factor when considering the obligation of new heating systems as tenants are less likely to accept disruption or cost for a new heating system when they only have a contract of a few years. Where a tenant has taken on a lease of 20 years, they may be more accepting to take on the cost or disruption of the system. This is due to the fact that 20 years is a similar time period to many heating system’s lifetime and the tenant will be able to benefit fully from the new system. However, it is a likely that a tenant with a 5-year lease would perceive any significant cost or disruption associated with a new heating system as disproportionate to the benefit they will receive.

In a multi-let building it is likely that there will be contracts with varying lengths of time left on them. This is illustrated in Table 1 below, which presents an example of the lease durations in an office block with six tenants. For example, some tenants may only have one year left on their contract, but the tenant next door may have just moved in and have eight years left on theirs. These tenants will have different views towards upgrading their heating system. For example, those with only a year left on their contract, and therefore only a year to benefit from a new heating system, are likely to be more resistant to paying for an upgrade or having disruption to their business caused by the upgrade. In many cases a communal heating system will be more efficient than separate systems in each part of the building.

Table 1: Hypothetical Illustration of multi-let office building with varying lease lengths in place

Development of green leases in Scotland

There has been work towards developing ‘green lease’ clauses by the Better Buildings Partnership (BBP).^[1] BBP argue that green leases are an important tool to ‘help to transform the environmental and social impact of a building’. They aim to support landlords and tenants by having a clear legal framework that establishes the roles and responsibilities for the delivery of environmental and social outcomes (Better Buildings Partnership, 2024). The BBP provide guidance and suggested wording for clauses in commercial leases that will support the decarbonisation of buildings. The BPP is a UK wide initiative and provide specific clauses for buildings in Scotland. There is no requirement to follow this guidance so any parties using these green leases will be doing so voluntarily. Green leases are becoming more utilised, but they are not widely used in the market. It is expected that as requirements for energy efficiency become more stringent and imminent more leases will seek to include green clauses (The Law Society, 2023).

Key learnings from similar policy mechanisms across Europe

We have identified several relevant policy mechanisms across Europe that have been previously implemented to promote clean heat in leased non-domestic buildings. The following section gives an overview of relevant policies and explore lessons learned.

Policy overview

Across Europe the regulatory landscape for clean heating in non-domestic buildings is relatively nascent. Most countries are yet to make significant progress with decarbonising their existing building stock. In the European Union, 85% of buildings were built before 2000 and 75% of those have poor energy performance (European Commission, 2024). There is also much less research and comprehensive data gathered for non-domestic buildings in Europe compared to domestic buildings, partially due to the varying nature of the non-domestic building stock (Kiviste & Musakka, 2023).

The revised EU Energy Performance of Buildings Directive in 2024 introduced a requirement for the gradual introduction of minimum energy performance standards for non-residential buildings based on national thresholds to trigger the renovation of buildings with the lowest energy performance. There have also been policies set in many European countries on the standards of new builds to reduce their CO₂ emissions and environmental impact (World Green Building Council, 2022).^[2] There have also been regulations introduced in many countries requiring decarbonisation of domestic buildings.

Table 2 shows the key information on relevant policy mechanisms that we have identified across European countries. Details for each policy mechanism is available in Appendix B.

Table 2 Policy mechanisms for heating in non-domestic properties in other countries

Successes and lessons learned

Promoting building energy efficiency and clean heating in the commercial real estate market

The French Tertiary Decree has raised awareness about energy efficiency improvements and clean heating within the real estate sector by establishing maximum annual final energy consumption targets that all stakeholders—whether owners of owner-occupied spaces, lessors, or tenants—must report each year. While financial sanctions for non-compliance are relatively modest (€1,500 for individuals and €7,500 for legal entities per building concerned), the decree includes a ‘name and shame’ mechanism (BMH Avocats, 2021).

As a result, the Tertiary Decree has led to significant changes in commercial real estate practices. According to CBRE Rive Gauche, a commercial real estate agency, the regulation has become central to real estate discussions, particularly concerning shared responsibilities like cost coverage and action management. Buyers and tenants are increasingly favouring tertiary buildings that meet the standards set by the decree and do not require major energy efficiency upgrades. The decree has also increased pressure on older, unrenovated buildings, making them less attractive to tenants and buyers, highlighting the critical need for energy renovations (CBRE Rive Gauche, 2024). France is particularly pushing for energy renovations and retrofitting where possible, rather than developing new buildings, as local authorities (municipalities) consider demolition a last resort (Real Asset Impact, 2024). There are financial incentives to help with energy renovation costs and clean heating, such as the Coup de Pouce Chauffage program (Ministry of Ecological Transition and Territorial Cohesion, 2024), which have driven the adoption of heat pumps in the tertiary sector (Ministy of Energy Transition, 2023a). The French Heat Pump Association highlighted a significant increase in the market share of heat pumps for retrofitting in the tertiary sector, rising from 7% in 2020 to 26% projected by 2026 (AFPAC, 2023).

Historically, the tertiary sector, which accounts for around 17% of France’s final energy consumption (ADEME), has shown an increasing trend in energy consumption (Hellio). The tertiary sector is also the second largest emitter of greenhouse gas in France (TotalEnergies, 2024), with a significant proportion of their final energy consumption still coming from petroleum products and natural gas (Ministry of Energy Transition, 2023b). Businesses typically did not prioritise energy savings or more specifically, clean heating, in the absence of regulatory obligations. However, since the introduction of the Tertiary Decree, it has been reported that many entities in the tertiary sector have made significant efforts to reduce their energy consumption while continuing to grow their business activities (Big media, 2024). Currently, the energy consumption of more than half of the French tertiary sector, covering nearly 600 million square meters, is being monitored by ADEME (ADEME).

A study also highlighted that the Dutch Energy Efficiency Policy for Offices, which mandates a minimum energy label of ‘C’^[4], has significantly driven energy renovations in office buildings compared to other commercial property types. Between 2018 and 2022, after the policy was announced, approximately 75% of office renovations improved the building’s efficiency rating to energy label ‘A’ or better. Notably, about 32% of these renovations involved office buildings that previously had an energy label of ‘D’ or worse. In contrast, only 17.5% of renovations in other commercial properties with an initial energy label of ‘D’ or worse achieved an upgrade to energy label ‘A’ or higher (Maastricht Center for Real Estate, 2023). Additionally, another CBRE report highlighted that office buildings with energy labels of ‘A’ or higher are now the most popular for commercial lettings, indicating a growing demand for highly efficient office spaces (CBRE, 2022). The report also noted that traditional financiers are becoming increasingly reluctant to invest in non-sustainable real estate, and when they do, they tend to offer loans at higher interest rates.

Lack of clarity

Some industry sources suggest that there has been confusion around the responsibilities incurred by and application of the non-domestic private rented Minimum Energy Efficiency Standard (MEES) in England and Wales. Landlords are the legal party obligated to deliver MEES but there are impacts and costs that could be passed on to tenants. MEES is likely to impact decisions around service charges, alterations and lease renewal negotiations for many landlords.

Opinions on MEES include that:

• ‘Government guidance is difficult to navigate in respect of lease renewals given the differing advice under the EPC and MEES regulations’ (Gordons LLP, 2023). The EPC Regulations 2012 require landlords to provide a valid EPC when selling a building, but not for lease extensions or renewals. However, MEES regulations mandate that if no valid EPC exists, a new one must be provided when leasing to an existing tenant. Failure to do so could technically prohibit lease extensions or renewals, highlighting inconsistencies between the two regulations (Gordons LLP, 2023).
• The current position in England and Wales will be creating a lot of uncertainty for landlords and tenants and many will be asking themselves:
• If their lease allows the landlord to enter the property to carry out improvement?
• And if so, what protection is given to the tenant to prevent significant disruption to their business?
• And whether the landlord can pass these costs to the tenant? (Mullis & Peake LLP, 2023)

There has also been a lack of enforcement of MEES with an industry investigation finding that local authorities, who are responsible for enforcing MEES, taking little to no action to enforce it (CMS, 2024). This is largely due to local authorities taking a ‘whistleblowing’ or reactive approach to enforcement due to lack of funding for enforcement.

Policy loopholes

The implementation of the MEES in England and Wales has faced challenges due to its complex policy design. In 2011, the UK Government announced that starting April 1, 2018, properties must meet a minimum performance standard at the point a letting when a lease agreement is made. As a result, until 2023, only leased properties are required to meet this standard, leaving owner-occupied properties excluded from the policy scope. Furthermore, having lease renewals as the trigger point for compliance means that, due to the continuity of occupancy, there may not be an appropriate window for the necessary upgrade work (McAllister & Nase, 2019).

The Flanders renovation obligation in Belgium also has a few loopholes, where some transactions are not subject to the legislation. As an example, a triple net lease instead of a long-term lease does not trigger the obligations. For context, a triple net lease is a commercial lease agreement where tenants pay all expenses in addition to the cost of rent and utilities, which typically includes real estate taxes, building insurance, and maintenance (Thomson Reuters Practical Law, 2024).

Similarly, structuring the transfer of ownership as a share deal instead of an asset deal also exempts building owners from the Flanders renovation obligations. However, if there was an existing obligation to renovate, this obligation transfers with the company and the timeline to complete the renovations remains unchanged, despite any corporate restructuring or share deal (Linklaters, 2023).

Insufficient lead time and support for implementation

A study by the Royal Institute of Chartered Surveyors has pointed out that the current proposed timeline and trajectory for MEES in England and Wales are increasingly viewed as unrealistic by industry players, and there is lack of implementation mechanisms. As a result, there is a risk that up to 50% of commercial buildings could be stranded by 2035 if no further action is taken (RICS, 2024). Recently, the UK Government, via DESNZ, has pushed the interim target of achieving an EPC rating C for all new non-domestic lettings from 2027 to 2028 (Energy Advice Hub, 2024). However, MEES goal for the non-domestic building stock to achieve a minimum of EPC B rating by 2030 remains unchanged. DESNZ viewed that this amendment would allow a sufficient lead in time for landlords to prepare for the legislation to come into effect once a government response is published (Elmhurst Energy, 2023).

Furthermore, issues and inconsistencies with the financial incentives for energy efficiency improvement measures have also resulted in both building owners/landlords and tenants incurring unexpected upfront costs for heating upgrades. The Green Deal, for instance, was designed to facilitate heating upgrades in residential and commercial properties at no upfront cost. However, the policy was discontinued after about two years due to design flaws, such as restricting full funding to investments with high rates of return (Rosenow & Eyre, 2016). Currently, there is the Boiler Upgrade Scheme in place for domestic properties in England and Wales, offering subsidies of £7,500 for heat pumps and £5,000 for biomass boilers (Ofgem). However, it has been reported that building owners/landlords and tenants may still face out-of-pocket expenses since typical heat pump installations often exceed the subsidized amount, especially when considering the cost of installation and additional components (BBC, 2024). This is contrary to the initial MEES England and Wales policy design, which intended to avoid upfront costs and ensure no net costs to landlords (McAllister & Nase, 2019).

Potential conflicts with tenants

A study reported that MEES for England and Wales has created complications for landlords when it comes to upgrading heating systems (McAllister & Nase, 2019). The applicability of MEES is triggered by lease renewals, but if a building is continuously occupied by tenants, it may be challenging to find a suitable time window for these upgrades. Additionally, the study identified that tenants often resist the disruption and costs associated with heating system improvements.

Unlike MEES, which does not legally require tenants to comply with upgrade work, the renovation obligations in Flanders explicitly states that tenants must accept the disruption caused by energy renovation, even if tenancies are ongoing but the building ownership has changed (Vlaanderen, n.d.). Under the Belgian Federal Commercial Lease Act, if the landlord is required to perform urgent work during the lease, tenants must allow the work to proceed and cannot claim damages or seek a rent reduction unless the work exceeds 40 days (DLA Piper, 2024). Urgent work is defined as any work that must be done immediately and cannot wait until the lease ends without ‘detriment’ (AMS Advocaten), which may include financial implications for landlords if the work is not completed by the renovation deadline. Therefore, tenants typically must accept and cooperate with the landlord during renovation works unless both parties agree to different provisions in the lease contract.

The French Tertiary Decree can also impact the landlord-tenant relationship by including a clause establishing shared responsibilities between the two parties. The Decree mentions that tenants are responsible for reducing energy consumption through behavioural changes during building operation. However, the Decree does not clarify who is responsible for installing energy-efficient equipment or covering the costs of energy renovation work. Furthermore, in practice, tenants may be charged for all renovation costs, including energy upgrades, if leases are signed after the Pinel Law came into effect on January 1, 2015 (Soulier Avocats, 2014). For context, Pinel Law or Loi Pinel is a French regulation aimed at promoting investment in rental real estate. It offers tax reduction for investors who purchase or construct a new build property and commit to renting it out for a minimum of six years. There have been some changes to the law since 2022, such as the tax benefits being progressively reduced for eligible properties built between 2022 and 2024 (FrenchEntrée, 2023). The French government plans to end the Pinel Law by the end of 2024 (Brahin, 2023). This situation could lead to significant disputes between landlords and tenants if their responsibilities are not clearly defined in the lease contract. On the other hand, energy performance improvements will affect the rental value of the property, which will be a key consideration in lease negotiations at the end or renewal of the lease (Seban Avocats, 2023).

Connecting to a heat network

Workshops with housing developers and non-domestic building representatives, as part of research carried out in 2022 for the Department for Business, Energy and Industrial Strategy (now DESNZ), found that mandatory connection to heat networks for non-domestic buildings may be perceive as too ‘black and white’ (BEIS, 2022). Instead, workshop attendees suggested a zoning system must account for the complexity of businesses’ individual heating requirements and participants encouraged market-based solutions rather than mandating connections. They considered clear communication and information on heat networks to be an important step in supporting non-domestic building stakeholders.

In surveys, as part of the same research project, respondents stated that their business pays ‘a fair amount or a lot of attention to the costs of their building’ and 84% stated that it is ‘somewhat, moderately or very important for their business to have the ability to switch heating or hot water suppliers’.

In France, local authorities can classify heat network areas. The classification makes it mandatory within that area to connect any new buildings or building undergoing major renovation work if they have an output over 30kW. The law started as voluntary in 2018 and became mandatory in January 2022. There are exemptions to the obligation to connect, including if the heat network is operating at a low temperature that is incompatible to the needs of the building or if the characteristics of the building do not allow a connection (Construction 21, 2023).

Analysing the impact on non-domestic stakeholders

As part of this project, we have carried out desk research and interviews with subject matter experts to understand potential impacts of the HiB Bill proposals on non-domestic buildings. This has included exploring the impact on stakeholder groups, lease arrangements and building types. Interviewees were asked about the impact of a requirement to upgrade non-domestic buildings, and how the impact would vary depending on whether there is a sale trigger point or just a backstop date.

The stakeholders interviewed represented the following types of organisation:

• Law firms
• Real estate services and investment companies
• Registers of Scotland
• Federation of Small Businesses

As outlined in Section 4, there are two key lease arrangements in Scotland, FRI and IR, with FRI leases being the most common. There is a huge variation in the clauses that will exist within leases so it is not possible to know exactly how each building, and its stakeholders, will be impacted without reviewing the specific lease(s). For the purpose of this project, we have provided an illustration of the impact on four key scenarios to explore how key stakeholders are likely to be impacted in each.

Through the desk-based research and interviews it became apparent that the lease type would not be the key factor affecting the impact of this policy on different stakeholders. Key variables are the presence of a single or multiple tenants in the building and the clauses in the contract between the tenant(s) and the landlord. Therefore, the two scenarios explore options of FRI leases where the clauses allow for different levels of cost and responsibility to be passed onto the tenant, each of these scenarios broken down into two to explore the impact on single-let and a multi-let buildings. For IR leases, it will similarly depend on the clauses and tenants in the building and similar outcomes can be expected. In scenarios 1 & 3 where the building is upgraded whilst it is empty there is an assumption that the vacant period is within any relevant grace period or backstop date.

• Single-let building where the clauses in the existing contract do not allow the landlord to pass on the obligation for a heating improvement to the tenant. Therefore, there is less incentive for the landlord to upgrade the property with the tenants in-situ and the nature of the upgrade makes it challenging to do so. Therefore, the landlord waits until the end of the existing lease period to upgrade.
• Single-let building where the landlord is able to transfer some or all of the cost of the new heating system onto the tenant. Therefore, the landlord chooses to install upgrades while the tenant is in the property to allow them to recover more of the costs.
• Multi-let building where the clauses in the existing contract do not allow the landlord to pass on the costs for heating improvement to any tenants in the building. Therefore, there is less incentive for the landlord to upgrade the property with tenants in-situ Therefore, the landlord waits until either parts of the building or the whole building is empty.
• Multi-let building where the clauses in the existing contract allow the landlord to pass on the cost to tenants through the service charge. Therefore, the landlord upgrades the property with the tenants in-situ.

The challenges identified in the desk research and interviews can be grouped into three key themes. We have used these themes to provide an impact score for each:

• Cost
• Disruption
• Legal complications

Each of these scores have been given to both landlords and tenants, and also building management organisations for the cost impact.

In each of these scenarios, we have assumed the existing heating system is a polluting system and will need to be replaced with a clean heating system, with some changes to elements such as the pipework and heating controls also required. There will be scenarios where the heating system requires minimal upgrades to meet the policy requirements and therefore will be a simple installation that can be easily done without causing significant disruption. In these cases, the disruption and cost impact will be much lower. The legal complexity will still depend on the clauses in the contract but there is likely to be less pushback from the tenant as the cost and disruption is low.

Summary impact assessment (cost, disruption and legal)

Table 4 below provides a summary of the impact analysis across cost, disruption and legal implications to landlords, tenants and building management companies. The impact score and assessment in the section below is our analysis based on the findings from the interviews in addition to the desk-based research. In the sections below, further detail on the scoring and the nuances in each scenario is provided. A scoring key is provided below.

Table 3: Scoring key

To note, these figures provide an indication of the likely impacts on different lease arrangements but there is likely to be substantial variation within each lease type based on the clauses agreed between the tenant and the landlord. The interviewees presented varying views on the impact and responsibilities on different parties, particularly the responsibility for the landlord or tenants to cover the cost of the new heating system. This illustrates the complexity of introducing these requirements and reflects the confusion over responsibilities that been found in England and Wales when introducing the MEES requirements (RICS, 2023).

Table 4: Summary of impact assessment

Cost impact assessment

Table 5 below provides an impact score for owners, tenants and building management based on the cost they could incur due to a requirement to upgrade their heating system.

Table 5: Cost impact assessment

We have provided insights on the impact on landlords and tenants in the sections below. Building management companies will not have a financial responsibility for the upgrades but they may have responsibility for delivering and coordinating the works. It is likely that if this requires more staffing they will charge a higher fee to the landlord. There may be more complexity for them managing tenants in a multi-let building

Single-let: landlord responsible for the cost

Owner / landlord: This scenario assumes the landlord waits until the building is empty to install the heating system. The landlord will pay for the full heating system and will lose out on rent while the building is empty as upgrades are taking place. They may be able to recover some costs for through charging higher rent to tenants after new heating system is installed.

Tenant: Directly incurs no cost of the heating system but has to move out at the end of the tenancy to allow works to be done. Additional cost of finding new working space and legal fees. New rents may also be higher due to landlords raising cost to cover this requirement. In addition, the new heating system may have higher running costs.

Further considerations:

• If the landlord is responsible for paying for and designing the new heating system there is less incentive to pick a system with lower running costs.
• If the new heating solution is a heat network the tenant may be responsible for higher costs and no ability to switch energy suppliers.

Single-let: costs passed onto the tenant

Owner / landlord: Responsibility to pay for some elements of upgrades (e.g. plant room). They are likely to incur legal fees to manage existing tenants.

Tenant: The tenant is required to pay for some or all of the new heating system.

Further considerations:

• If the requirement to upgrade is triggered by a building sale the tenant is likely to have no foresight of that and taking on any additional costs for a new heating system could be very challenging.
• If the new heating solution is a heat network the tenant may be responsible for higher costs and no ability to switch energy suppliers.

Multi-let: landlord responsible for the cost

Owner / landlord: The landlord will pay for the full heating system and will lose out on rent while the building is empty as upgrades are taking place. With multiple tenants it takes longer to get the building fully occupied again, meaning they receive reduced rent. They may be able to recover some costs for through charging higher rent to tenants after new heating system is installed.

Tenant: Tenant directly incurs no cost of the heating system but has to move out at the end of the tenancy to allow works to be done. Additional cost of finding new working space and legal fees. New rents may also be higher due to landlords raising cost to cover this requirement. New heating system may have higher running costs.

Further considerations:

• It is likely to be challenging in many cases to agree responsibility of costs if the clauses in the contract are not clear
• If the new heating solution is a heat network the tenant may be responsible for higher costs and no ability to switch energy suppliers

Multi-let: landlord responsible for the cost

Owner / landlord: Landlord passes on majority of cost obligation to tenant.

Tenant: Tenants pay for new system through the service charge. For tenants with longer leases they may be more accepting of this cost but likely tenants with shorter time left on their lease to accept this.

Further considerations:

• It is not clear how costs would be shared across multiple tenants with varying contract terms and different bargaining power.
• If the new heating solution is a heat network the tenant may be responsible for higher costs and no ability to switch energy suppliers

Disruption impact assessment

Table 6 below provides an impact score for owners, tenants and building management based on the disruption they could incur due to a requirement to upgrade their heating system.

Whilst we have provided an indicative score to give an understanding of the level of impact on different stakeholders there will be variety in every case. The level of disruption will vary significantly depending on the level of upgrade needed and type of business. Key factors in the level of disruption include:

• Size of retrofit project: For example, upgrading from a gas central heating system to a heat pump or connecting to a heat network would be a major retrofit project.
• Type of business: For example, if the property needs to be empty for one week this will be more of an issue to a shop (who will miss out on business) than an office (whose employees could work from home).
• Ability to provide back-up heating.
• Availability of workforce to deliver upgrades (e.g. there could be delays to the project if there are no skilled workforce available to carry out the works).

Table 6: Disruption impact assessment

Single-let: landlord responsible for the cost

Owner / landlord: Landlord responsible for installation of new system when the property is empty. Significant challenges to determine what heating system and find skilled workers to install quickly and minimise the time without tenants, and therefore without rent.

Tenant: Tenant may have planned to renew contract but will be removed from the property to allow upgrades to happen. There may be challenges finding new properties that haven’t got higher rent or likely to yet to be upgraded (and therefore at risk of requiring upgrades in future)

Single-let: costs passed onto the tenant

Owner / landlord: It will be very challenging for the landlord to agree with the tenant to install the new heating system while they are in the building.

Tenant: A new heating system (particularly if transitioning to a heat network or heat pump) will be extremely disruptive. Tenants may need to temporarily move out to allow the works to take place.

Further considerations: Even once a new system is in place it may cause disruption to the tenant as it may not meet the needs of their business as well as the old system as efficiently or cost effectively.

Multi-let: landlord responsible for the cost

Owner / landlord: Tenants are likely to be at different points in their contract (e.g. one could have 12 years left in the building and one could have 2 years). It will be challenging for landlord to arrange for unoccupied period for upgrades.

Tenant: Tenant may have planned to renew contract but will be removed from the property to allow upgrades to happen. There may be challenges finding new properties that haven’t got higher rent or likely to yet to be upgraded (and therefore at risk of requiring upgrades in future).

Further considerations: Different tenants may have different heating requirements and new systems may not meet their needs.

Multi-let: landlord responsible for the cost

Owner / landlord: It will be very challenging for the landlord to agree with the tenant to install the new heating system while they are in the building

Tenant:

• A new heating system (particularly if transitioning to a heat network or heat pump) will be extremely disruptive. Tenants may need to temporarily move out to allow the works to take place.
• If there is a central heating system for the whole building, there is a risk that the new system does not work as well for some businesses

Further considerations: Even once a new system is in place it may cause disruption to the tenant as it may not meet the needs of their business as well as the old system (e.g. a business needing large volumes of hot water on demand).

Legal impact assessment

All parties will want to reduce the cost and disruption in their business so will aim to identify the relevant clauses in the contract that will prevent them taking on this cost or disruption. It is likely there will be cases where there is some ambiguity in the obligation with existing contracts which will add complexity. However, in other cases there will be clear responsibility and limited legal negotiations.

Table 7 provides an assessment of the legal impact on both the landlord and tenant.

Table 7: Legal impact assessment

Key factors in the impact on different stakeholders

This section provides an illustration of the nuances within each scenario and the challenges associated with different arrangements. There were varying and uncertain views expressed from stakeholders about the impact of this policy on different parties but there was agreement that upgrading non-domestic buildings would be very challenging in many cases. The impact will vary depending on the type of building, the lease arrangement and the specific requirements and timeframe of the property (e.g. whether the requirement is triggered by a property sale or long lease and the length of the grace period).

Installing low carbon measures with tenants in-situ

As demonstrated in Table 8, if there are tenants in the building, and the clauses in the contract allow it, the landlord will want to pass on as much of the cost to the tenant as possible, either through their direct responsibility for parts of the building or through the service charge for communal areas. There will be some cases where the upgrade to low carbon heating is a simple installation that can easily be done without significant disruption to the tenants. However, many low carbon upgrades will be very disruptive to the tenant and in some cases will not be able to be delivered while the tenant is using the property, for example if converting to a heat pump or low temperature heat network which requires changes to the pipework in the building. The impact of this will vary depending on a number of factors, including the complexity of the work, and therefore the time needed for the upgrade, and the ability of the business to continue operating in this period.

Multi-let building leases

While both stakeholders in both single-let and multi-let buildings will encounter significant challenges complying with a requirement to upgrade their heating system, all law firm and real estate investment interviewees agreed that lease arrangements in multi-let buildings, is the more complicated scenario. One interviewee stated that “in multi-lets you may not have a time whereby all occupiers are at the end of their lease at the same point and therefore landlords may not have the opportunity to come in and make refurbishments”. If a landlord is responsible for carrying out the works, there will be significant challenges in delivering any upgrades whilst tenants are in the building. Many leases will have clauses preventing a landlord entering the tenants’ part of the building. For the landlord to arrange the upgrade with all tenants will be very complicated.

Additionally, as set out in Table 1 above the leases in the building are likely to vary in length and there may not be an obvious trigger point when the building is vacant.

Challenges associated with trigger of sale/long lease

The requirement to upgrade within a certain timeframe after property sale was a concern expressed by most interviewees. Upgrading a heating system will be a large project in many buildings and some interviewees argued that where possible the upgrade should be done at the most appropriate time in the building’s lifecycle, such as when a refurbishment is due.

If a trigger point is based on a purchase, or long lease change, this could cause significant challenges for the tenant. Tenants are unlikely to have any visibility or control over the sale of a property. If they do not know when a building is going to be sold, and the sale of the building leads them to either take on some cost of a new heating system or disruption to their business, this could be a significant challenge for their business. Without any foresight into when this may happen, they cannot budget for that cost. some interviewees commented that a two-year grace period would be far too short for many business tenants to find funding for a new heating system. One interviewee started the interview discussion by stating that the “trigger point is very important” and was a significant point of concern for them.

One interviewee suggested a two-track system for the grace periods. This would mean the party involved in the transaction would have a shorter grace period and tenants, if they have responsibility, would have a longer grace period. This would support tenants where they were not aware the sale was coming up and have not been able to build it into their business plan.

Others suggested that a policy deadline, without a sale or long lease trigger, would be far easier for building stakeholders to comply with and would allow stakeholders to appropriately plan for the upgrades. This would allow obligated parties to build trigger points, such as vacant possession and refurbishment cycles, into their retrofit plan.

Shortages of skilled workers

Another challenge for the party upgrading the system will be identifying the appropriate heating system and finding the skilled workers to deliver it. One interviewee pointed out that if there is a requirement for many buildings to upgrade their systems in the next few years there is unlikely to be sufficient skilled capacity in place to deliver this. There needs to be sufficient investment in the low carbon heating sector and its skilled workforce, and the design of the regulation needs to consider situations where parties are looking to upgrade their heating but cannot meet specified timelines due to workforce shortages. Without this there is likely to be significant delays to heating upgrades which would heighten the impact on both landlords and tenants.

Conflicting requirements

Assuming the obligation is set on the landlord, the requirement to improve a heating system could conflict with other requirements in their contract with the tenant. Many retrofit projects will be very disruptive to tenants and potentially stop them from being able to operate for a period of time. For example, the Property Standardisation Group (PSG)’s model ‘Commercial Lease of Part of a Building’ (Property Standardisation Group, 2024) includes the following clauses for the landlord to comply with:

• “Cause as little interference to the Tenant’s business as reasonably practicable”
• “Where entering to carry out works, obtain the Tenant’s approval to the location, method of working and any other material matters relating to the preparation for, and execution of, the works”

The first clause will be difficult to comply with if the landlord needs to undertake significant works which cause disruption to the tenant. It is likely that tenants will not approve the works being done to allow the landlord to comply with the second clause.

For context, the PSG is an association established to create standardized documents and procedures for Scottish commercial property transactions (Law Society of Scotland, 2021).

Challenges for different building use

The focus of the research was on lease arrangements. However, due to the diverse nature of the non-domestic building market the challenges varied significantly by building use. The table below provides an overview of the key considerations and challenges for different types of non-domestic buildings that interviewees raised, with an estimate of the proportion of the market that type represents. This is the estimated percentage of the ~270,000 non-domestic properties in Scotland, based on Energy Saving Trust analysis for the Scottish Government. See Figure 1 above for more information.

Table 8: Table summarising challenges based on building use

Small business impact

One interviewee pointed out that there are several factors associated with the non-domestic property market which would likely result in smaller businesses (less than 100 employees) being disproportionately affected by the introduction of this measure:

• Lack of capital to fund heating upgrades: The replacement of a heating system is likely to incur a significant capital outlay. Unlike larger businesses, it is unlikely that smaller businesses will be able to access the capital required to fund this kind of investment. This is particularly an issue where the trigger for upgrades is the sale of a property and the tenant is a small business as they would not have oversight of when a property is due to be sold and therefore would not be able to accurately build any funding needed for heating upgrades into their business plan.
• Less bargaining power: Small businesses are less likely to be able to negotiate and agree favourable terms with a landlord as they may not be able to pay for the same level of legal support as a larger organisation. This could have implications for the type of obligations that are placed on the tenant or the share of the costs that are incurred.
• More likely to be in multi-let: Due to their size, small businesses are more likely to be in multi-let premises, rather than the sole tenant in a single building. As discussed in the previous section, there are more complications associated with the implementation of this measure in a multi-let building.
• More likely to be in marooned buildings^[5]: Small businesses are more likely to currently occupy commercial buildings with lower rental fees. One interviewee stated that buildings are more likely to be located outside of central business areas and therefore may be more exposed to a reduction in property prices due to the introduction of a requirement to upgrade to low carbon heating. If the measure leads to the sale of these properties, then small businesses may have to relocate.

Assessment of the wider impact on the Scottish non-domestic property market

As outlined in the previous sections the varied nature of the non-domestic market means that implementing any new policies without careful consideration of the different lease arrangements, building types and stakeholders could have significant detrimental impacts on the market. Interviewees provided insights on the potential impacts of the market, which included property prices falling, stagnation in the market and marooned buildings.

Property prices

As set out in section 3.1.1.1, some non-domestic buildings have already started to decarbonise their heating systems. A greener work space can be used as a route to attract tenants and charge higher rent. Therefore, properties which have low-carbon heating systems may increase in value. However, some interviewees observed that if there is a requirement to upgrade a building’s heating system when buying a building it is likely that buyers will underbid for the property based on the estimated cost of upgrading the heating system. It would be very challenging for buyers to know how much it will cost to upgrade the system and therefore they may need to overestimate the cost, so they do not overpay for the combined cost of the building and the new heating system.

There will also be an impact on mortgage lenders if the property prices fall. As seen with MEES in England and Wales, lenders are likely to be concerned about the possible adverse effects of any low carbon heating requirements impacting the reliability of landlords receiving rent due (i.e. their income stream to service the borrowing). Industry observations include that lenders may want to impose their own requirements for building efficiency to protect their position (Womble Bond Dickinson, 2018).

Marooned buildings

The cost of installing and operating a low carbon heating system could vary significantly across buildings. For example, the installation may be particularly complex, require additional works (e.g. energy efficiency measures), or may need to adhere to local building codes. This could deter buyers from buying properties or tenants from taking on leases in properties where they know they may take on the cost or disruption of a heating system upgrade. This could lead to situations where buildings are left vacant.

One interviewee observed that this is more likely to happen to buildings used by smaller businesses and start-ups and outside the main cities of Edinburgh, Glasgow and Aberdeen where lower rents and less demand in the market may not make the investment of a new heating system viable. This would compound the negative impact of Covid on occupied offices and the value of office space. The amount of unoccupied office space is currently already at its highest level in the UK since 2014, up 65% in the last 3 years (UK Green Building Council, 2024b). One interviewee observed that “there has been a significant reshaping of the office market since Covid and tenants are now focusing more heavily on smaller but better quality spaces”.

Stagnation in the market

Uncertainties around the responsibility and costs of new heating systems could cause a slowing of the market. One interviewee stated that “if tenants are responsible for upgrades they may get in a situation where they are meant to upgrade their heating system before the leave but haven’t done so and get locked into their working space”. The potential cost and disruption of a heating system replacement may cause some tenants to not want to move into new buildings if they are aware the current system is polluting. The negotiations around responsibility could also increase the amount of time preparing new lease agreements.

The need for cooling in non-domestic buildings

One interviewee also raised that the need for cooling in non-domestic buildings should be included in the policy design. In some non-domestic buildings, it is likely there will be some need for cooling and the interviewee argued that this needed to be part of the policy decision. Without the incorporation of cooling into the decision there may be additional complexities for stakeholders needing to navigate upgrading their heating systems and providing cooling.

Conclusions

The challenge

The requirement to upgrade non-domestic buildings will be a significant challenge for many stakeholders and will require careful policy design to reduce the impact on non-domestic building stakeholders and the property market in Scotland.

When applied to the non-domestic sector, the cost of complying with a property purchase trigger is likely to be passed on to building tenants. However, the ability to pass on this cost will depend on the clauses in each contract and the drafting of the legislation.

Commercial leases are complex, and the introduction of this measure is likely to face legal challenges. Commercial leases are not standardised across Scotland meaning that landlord / tenant arrangements and relationships will vary significantly. Our research identified the following legal complications that could be incurred through the introduction of this measure:

• Clarity on obligations: Contracts may not provide sufficient detail to identify precisely the costs that are allocated to the building landlord or tenant. This is likely to be particularly prevalent in a multi-let building, whereby the installation of a heating system will require improvements to both communal and private areas of the building. If these areas are not sufficiently well specified in the contract, this will likely lead to legal disputes between the tenant and landlord.
• Conflicting obligations: The introduction of this measure could conflict with the landlord’s current obligation to provide the tenant with a ‘fit for purpose’ premises.
• Cost sharing: In multi-let premises, buildings will likely be occupied by multiple tenants with varying contractual arrangements. As such, it is likely that there will be variation with regards to the amount of time each tenant has left on their contract and the extent to which they are liable for the compliance costs. These factors add complexity for the landlord and would likely to lead to further legal complexities as each tenant negotiates their level of responsibility and cost ownership.

The trigger point for the obligation is an important policy decision that could have a significant impact on the effectiveness of the measure. The consultation stipulates that the sale of the building would act as the trigger point from which new building owner would be obliged to install a low-carbon heating system by a certain date (the grace period). In the non-domestic setting, there is a risk that this approach may add cost and uncertainty to current building tenants. If the building sale is used as the trigger point the tenant may not have any control or oversight on when the trigger is enacted. In practice, this could lead to a situation whereby the obligation is placed on the tenant at a time which they are unable to pay, or at a point which could cause maximum disruption to their business operations.

Interviewees suggested a backstop date would provide the tenant with more certainty regarding the timing of the obligation, allowing them to better prepare and plan their business for the implementation of the obligation and build other trigger points, such as vacant possession and refurbishment cycles, into retrofit plan. Further consideration would be needed as to whether this backstop date should be prior to 2045 if there is no property purchase trigger.

Lessons for policy

The design of the measure should be tailored to the conditions in the non-domestic market. A specific non-domestic policy should be considered which ensures that the measure can complement market arrangements and conditions that are unique to the non-domestic property market.

Our interviews demonstrated that even key stakeholders in the non-domestic building market in Scotland are unclear on the impacts and responsibilities of this policy if it were introduced. The non-domestic building market, and the lease arrangements, is complex and varied and there is no simple ‘one size fits all’ approach that can be taken.

Industry engagement is important to ensure that costs are minimised, and risks are mitigated against. Commercial businesses are diverse in their operations, the buildings they occupy and the leases they have agreed. As a result, the potential level of disruption, costs and level of legal complications associated with the introduction of this is likely to vary significantly across businesses depending on their circumstances. Industry engagement is critical to ensure a wide range of views are incorporated into the policy design.

Further considerations for policy raised through this research are:

• The length of the grace period to balance the urgency of decarbonisation against the impact on industry. A longer grace period, of more than two years, would provide SMEs with more time to acquire the capital required to comply with the measure.
• Exemptions or allowances could be built into the policy design to mitigate the impact on stakeholders.
• Financial support would help businesses fund any required upgrades. However, policymakers should carefully consider the type of support provided as small businesses may not be in a position to take on more debt (i.e. via a loan-based instrument).
• Routes to support landlords and tenants with their legal arrangements: there may be lessons learnt from parties that have already started using ‘green leases’.

Priorities for further research

An option to get a more detailed understanding of how policy options could impact stakeholders would be to run trials to identify the impacts on a particular area. For example, this could involve selecting a street or small area and collecting details on the buildings in that area and the leases in place. It is important to have ambitious decarbonisation targets but for these to work effectively there needs to be active engagement with stakeholders, to understand how to design the policy that best supports this decarbonisation and the market.

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Appendices

Appendix A LCP Delta non-domestic property estimates

The table below shows the full breakdown of non-domestic properties in Scotland from a Scottish Assessors report (Scottish Assessors, 2024). LCP Delta then estimates the proportion of each property category to require heating based on Scottish Assessors’ definition and examples of each property classification.

Appendix B Policy overview

Below are details for the policies mentioned in Section 6:

Minimum Energy Efficiency requirements in England and Wales

The Minimum Energy Efficiency Standard (MEES), originating from the Energy Act 2011, has been gradually implemented to improve energy efficiency in both domestic and non-domestic privately rented properties in England and Wales, specifically those with an Energy Performance Certificate (EPC) rating of F or G. The details and legal foundation for MEES are provided in the Energy Efficiency (Private Rented Property) (England and Wales) Regulations 2015 (BEIS, 2021). MEES initially took effect on 1 April 2018. From this date onward, landlords of privately rented domestic and non-domestic properties in England and Wales were required to ensure their properties achieved a minimum of EPC E before granting a new tenancy to new or existing tenants. This applied to new, renewed, and extended tenancies. Starting from April 2023, this requirement was extended to include all tenancies for non-domestic buildings, including for ongoing tenancies regardless of whether there was a change in tenancy. Furthermore, there are discussion that the Government will increase the target minimum efficiency to EPC B by 2030 (Auditel, n.d.). The responsibility of ensuring a property complies with the MEES legally falls on the landlord. However, in practice the associated costs for system upgrade will depend on the wording of the lease (both new and existing leases) (RICS, 2023).

Exemptions are available for reasons such as the required works do not meet ‘the Golden Rule’ (a seven-year payback period on expenditure on improvements), leases are for less than six months or consent to carry out the premises from the tenant has been refused. The regulations are also exempt for properties that are not legally required to have an EPC, i.e., properties let before 1 October 2008 (DESNZ, 2019). Landlords can self-certify their exemptions by registering through an online portal known as the PRS Exemptions Register. While the EPC for a property can be transferred if the property is sold, any registered exemptions will not transfer and will cease to apply once the property is sold (McAllister & Nase, 2019).

The potential fines for not complying with MEES are given to landlords by the Local Authority. This can reach up to £150,000 for non-compliant landlords, administered progressively based on the duration of the non-compliance. Rental of non-compliant properties of less than 3 months would see a fine of 10% of the rateable value, and 20% for more than 3 months of non-compliant tenancy (Business Companion, 2022).

Section 63 of the Climate Change (Scotland) Act 2009 – The Assessment of Energy Performance of Non-domestic Buildings (Scotland) Regulations 2016

The Assessment of Energy Performance of Non-domestic Buildings (Scotland) Regulations 2016 was established under the Section 63 of the Climate Change (Scotland) Act 2009. These regulations apply to owners of non-domestic buildings, requiring them to assess and improve the energy efficiency, and effectively reduce the greenhouse gas emissions associated with their building. Regulations apply from 1 September 2016 for buildings larger than 1,000 m², mandating building owners to provide a valid Energy Performance Certificate (EPC) on the point of sales or lease to a new tenant. Buildings that already meet the energy standards equivalent to the 2002 building regulations or have already installed measures via a Green Deal are exempted from the regulations (Scottish Goernment, 2020).

Tertiary Decree in France

The current Tertiary Decree (Decret Tertiaire or Decret Éco Énergie Tertiaire), was legally enacted in 2019 by the French government, requiring all tertiary buildings of more than 1,000 m² in France to lower gradually their energy consumption. Previously, a similar regulation was defined in 2010 (i.e. the Grenelle 2 Law), which set requirements around energy renovations for tertiary buildings. Both building owners and tenants of tertiary buildings are subject to this regulation. ADEME monitors how buildings comply to this regulation through an online platform. Tertiary building owners/tenants are required to submit their energy consumption report annually to the platform. The energy management aspect, however, can be delegated to a private service provider (ESCo) or network operators. Failure to report this could result in a fine ranging from EUR 1,500 to 7,500 if the corresponding party does not respond to a formal notice given after 3-6 months from the reporting deadline (OPERA energie, 2024). Since the regulation was enforced in 2019, the French tertiary sector has reduced its energy consumption by 23% by 2024 (Bat info, 2024).

Renovation obligation in Belgium

The energy standards and renovation obligations for non-domestic buildings in Belgium will vary by region. Flanders has enforced a renovation obligation policy, while Wallonia and Brussels have yet to publish detailed legislation but have announced plans to do so (Monard Law, 2024).

From January 1, 2022, non-domestic buildings in Flanders with an EPC rating of F or worse must undergo energy renovations at the point of sale/transfer. Responsible entities have five years from acquiring full ownership or establishing or transferring a ground lease or building right, to complete the required renovations and achieve a minimum EPC rating. This obligation applies to the new building owners in case property sale/transfer and to landlord or leasehold owner in case of long-term leases. If there are multiple owners or leasehold owners, each is responsible for complying with the renovation requirements. Required measures include replacing central heating systems older than 15 years at the time of acquisition. In case for rented properties, tenants will have to comply with the possible disruption caused by the renovation work (Vlaanderen, n.d.). For buildings up to 500 m², the minimum EPC rating is C, effective January 1, 2022. Larger buildings (over 500 m²) must include onsite renewable energy production meeting at least 5% of the building’s annual energy consumption, effective January 1, 2023. All non-domestic buildings must reach the minimum EPC rating by January 1, 2030, regardless of ownership transfer. If a building has been owned for longer than five years, landlords must obtain an EPC assessment to then determine if renovations are needed. Landlords are also required to apply for a new EPC assessment after any energy renovation works have been completed. Non-compliance can result in a fine ranging from EUR 500 to 200,000 (Linklaters, 2023).

Minimum energy efficiency standard for commercial offices in the Netherlands

In late 2016, the Netherlands announced the introduction of a regulation similar to MEES for all commercial office buildings by January 1, 2023. Offices were prioritised over other building types because a large proportion of office buildings have an EPC rating of D or worse, or may not have an EPC at all. Like the MEES in England and Wales, the regulation includes seven years notice period for building owners. In the Netherlands, a cliff-edge rather staged approach has been taken and from 1 January 2023 all office stock is expected to achieve minimum EPC C (Rijksdienst voor Ondernemend Nederland, 2018). In England and Wales it is only stock involved in a specified transaction that are imposed to the MEES (McAllister & Nase, 2019). As such, Compared to the England and Wales MEES, a much large proportion of the office building stock in the Netherlands will be affected.

Building Energy Act in Germany

The latest update to the Building Energy Act (Gebäudeenergiegesetz or GEG) mandates that building applications for newbuilds situated in new development areas submitted on or after January 1, 2024, must use at least 65% renewable heating and/or cooling (BMWSB, 2024). This effectively limits heating system choices to options like district heating, biomass or biomethane boilers, or heat pumps, thereby banning fossil-based heating systems.

The deadline for newbuilds located outside new development areas varies by German state and municipality size. Large cities (over 100,000 inhabitants) must comply by June 30, 2026, while smaller cities have until June 30, 2028. Existing buildings have extended deadlines and are not strictly required to replace their current heating systems. Existing fossil-based systems can also be repaired if they fail and do not need to be replaced with clean systems. GEG appoints landlords to take the main responsibility for complying to this law. Landlords are also allowed to include the heating system upgrade costs within the basic rental price. However, a tenant protection clause in the GEG caps the amount landlords can pass on to tenants at 8-10% of the investment costs (Federal Ministry of Justice, 2024).

Heat Network Zoning in Scotland and England

Heat network zoning is a process to designate areas where heat networks are expected to offer the lowest-cost solution for decarbonising heat. In England, heat network zones will be identified using a standardised national zoning methodology (DESNZ, 2024).

The Heat Networks (Scotland) Act 2021 requires each local authority to review whether any areas in its jurisdiction are suitable for heat network development. Key stakeholders (the local authority and Scottish Ministers) then decide whether the local authority or the Scottish Government should proceed with designating heat network zones (Scottish Energy and Climate Change Directorate, 2023).

Energy Climate Law (Heat Networks) in France

The classification allows a local authority to impose the connection to a heating network within a priority development area. Within a specific area surrounding the network, referred to as the priority development area, it is mandatory to connect to the heating network for:​ 

• any new building with heating needs exceeding a certain capacity (30 kW or more)​ 
• any building that is upgrading its heating system and has an output above a certain level (30 kW or more).​ 

There are 3 conditions that must be met for heat networks to be ranked: ​ 

• ​The network must be supplied by at least 50% of renewable or recuperated energy​ 
• Quantities of energy delivered per delivery point are metered​ 
• The financial balance of the operation during the depreciation period is guaranteed​ 

In France, in 2023, there are 636 heat networks classified.​ In 2019, the Energie Climat law reversed the logic of network classification, stipulating that, starting in 2022, any network that meets the criteria is classified by default, unless the local authority decides otherwise or the building is concerned by a derogatory case (technical incompatibility, greener renewable alternative solution). 

How to cite this publication:

Cheetham, A; Angela, I; Buzzing, J and Hadfield, M. (2024) Assessing the impact of the Heat in Buildings Bill on leases in the non-domestic sector, ClimateXChange. http://dx.doi.org/10.7488/era/5039

© The University of Edinburgh, 2025
Prepared by LCP Delta on behalf of ClimateXChange, The University of Edinburgh. All rights reserved.

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

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. 
   

   The Better Buildings Partnership is a collaboration of property owners who are working together to improve the sustainability of commercial buildings in the UK. ↑

   
   
2. 
   

   European countries with new-build requirements include Denmark, Finland, France, the Netherlands and Sweden. ↑

   
   
3. 
   

   Tertiary buildings are buildings used for businesses that provide services but do not produce goods, for example banks, hotels, offices, etc. ↑

   
   
4. 
   

   The Dutch energy labels indicate a building’s energy use. An energy label ‘C’ means that a building’s primary fossil fuel energy consumption does not exceed 225 kWh per square meter per year (Netherlands Enterprise Agency RVO). In contrast, EPCs for non-domestic buildings in the UK are rated on a scale from 0 to 150+, based on a building’s energy efficiency. This rating reflects the energy used for space heating, water heating, ventilation, and lighting for a building, compared to those of a reference building (Department for Communities and Local Government, 2017). An EPC C means that a non-domestic building receives a rating of 26-50 (EEABS). ↑

   
   
5. 
   

   ‘Marooned buildings’ refers to properties that have become isolated or stranded. ↑

   
   

Achieving Scotland’s net zero goals by 2045 will require significant expansion of the renewable energy workforce.

This study assesses the current training provision for the onshore wind and solar energy sectors in Scotland, identifying gaps, barriers and opportunities for improvement.

The researchers conducted desk research, data analysis and stakeholder consultations.

Findings

• The skills needed in the solar and onshore wind sectors can be divided into sector-specific, allied STEM (science, technology, engineering, and mathematics) and other skills.
• There is a strong breadth of allied STEM training provision in Scotland, with skills that are highly sought across multiple sectors.
• A siloed approach to STEM workforce planning is a threat, as several industries draw from the same talent pool.
• Stakeholders highlighted poor visibility of careers, as well as low job attractiveness, as major barriers to the development of solar and onshore wind sectors at the accelerated pace required.
• There is a shortage of specialised training provision providing essential skills for the construction and operational phases of solar and onshore wind projects. The solar sector, in particular, suffers from a lack of training specific to large-scale or ground-mounted solar installations.
• The majority of targeted training provision relevant to solar and onshore wind sectors is largely theory-based, with insufficient emphasis on practical, hands-on experience.
• Funding constraints are a significant barrier to the expansion and modernisation of training programmes.
• Industry uncertainty, driven by a lack of clear and stable policy directives, complicates long-term planning for workforce development.
• The competition for technically skilled workers is fierce across various industries, which complicates talent acquisition and retention.

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.

Research completed: January 2025

DOI: http://dx.doi.org/10.7488/era/5399

Executive summary

Aims

Achieving Scotland’s net zero goals by 2045 will require significant expansion of the renewable energy workforce. This is especially true in the rapidly growing onshore wind and solar energy sectors. Forecasts indicate a dramatic increase in workforce demands by 2030. This emphasises the need for enhanced, well-aligned training programmes to develop a skilled labour pool.

This study assesses the current training provision for the onshore wind and solar energy sectors in Scotland, identifying gaps, barriers and opportunities for improvement. It analyses existing programmes and their alignment with industry needs, exploring future workforce demands and strategies to address skills shortages.

Findings

We conducted desk research, data analysis and stakeholder consultations. The skills needed in the solar and onshore wind sectors can be divided into sector-specific, allied STEM (from broader disciplines such as mechanical and electrical engineering) and other skills (Figure 2). Although some critical training provision is needed for solar and onshore wind separately, the majority of roles are shared by the sectors requiring allied STEM and other skills. Siloed approaches for skills governance in solar and onshore wind could be counterproductive as the sectors compete for many of the same skillsets.

Figure 1. Conceptual framework of skill types relevant to solar and onshore wind industries.

We found that:

• There is a strong breadth of allied STEM training provision in Scotland, with skills that are highly sought across multiple sectors. A siloed approach to STEM workforce planning is a threat, as several industries draw from the same talent pool. Stakeholders highlighted poor visibility of careers, as well as low job attractiveness, as major barriers to the development of solar and onshore wind sectors at the accelerated pace required.
• There is a shortage of specialised training provision providing essential skills for the construction and operational phases of solar and onshore wind projects. The solar sector, in particular, suffers from a lack of training specific to large-scale or ground-mounted solar installations.
• The majority of targeted training provision relevant to solar and onshore wind sectors is largely theory-based, with insufficient emphasis on practical, hands-on experience. Industry leaders are concerned that graduates often lack real-world skills and are not “work-ready” upon entering the workforce. Practical training opportunities, such as industry partnerships and on-site apprenticeships, are limited.
• Funding constraints are a significant barrier to the expansion and modernisation of training programmes. High-cost courses, such as those involving high-voltage systems and specialised certifications, require substantial investment in equipment and facilities. Many colleges and training providers struggle to secure adequate resources to enhance the training delivery.
• Industry uncertainty, driven by a lack of clear and stable policy directives, complicates long-term planning for workforce development. Industry is hesitant to invest in apprenticeships and workforce training without concrete indications of project pipelines and future market stability.
• The competition for technically skilled workers is fierce across various industries. Renewable energy companies compete among themselves and with other sectors for these workers. This high level of competition complicates talent acquisition and retention.

Lessons learnt

The content and delivery principles of training programmes needs to be updated to better equip trainees with practical, hands-on experience. Deeper collaborations between industry stakeholders and educational institutions would ensure curricula content is relevant and meets current and future sector needs. Educational institutions and training providers should integrate work-based learning modules, internships and apprenticeship opportunities into their curricula. Modular and more flexible courses as a core mechanism for training delivery would facilitate targeted, intensive upskilling or reskilling. Such flexibility would enable faster and more efficient transitions into the workforce.

There is a pressing need for increased and targeted funding to support technical training programmes to enable these updates.

To attract and retain a skilled workforce, the onshore wind and solar sectors must become more visible and appealing to job seekers. Development of career pathway maps would illustrate how individuals can progress from entry-level roles to senior positions. This would provide a clearer picture of the long-term opportunities available in the sector, making it more attractive to potential recruits.

An integrated perspective is necessary to consider the requirement for a STEM workforce across all infrastructure projects of national importance and overall installed capacity ambitions. A comprehensive map that details the scale, timelines and workforce demands of major infrastructure projects has the potential to inform the total scale of skilled workforce needs, including for the onshore wind and solar sectors.

Next steps

Effective workforce development will require close collaboration between government, industry and educational institutions, and workforce representative groups. A coordinated approach will ensure that training programmes are aligned with sector demands. To address the workforce and training challenges outlined in this report, a detailed, comprehensive action plan should be developed. This plan should include timelines, assigned responsibilities, and measurable outcomes to ensure progress is tracked and accountability is maintained.

With workforce demand projected to peak by 2027, the action plan must be implemented swiftly. Initiatives should be launched before the start of the 2025/2026 academic year to allow training providers time to adapt and scale. This proactive approach will enable the industry to meet pressing needs and support for the Scottish Government to deliver its renewable energy commitments.

Glossary / Abbreviations table

Introduction

Scale of skills demands in solar and onshore wind

The achievement of Scotland’s net-zero commitment by 2045 relies heavily on expanding the renewable energy sector, including the onshore wind and solar energy sectors. Both the wind and solar sectors are expanding rapidly, creating an urgent need to train a larger skilled workforce. Two recent studies published by the ClimateXChange have estimated the workforce needs for both these sectors.

In the onshore wind sector, the workforce could need to increase from around 6,900 full-time equivalent (FTE) jobs in 2024 to an estimated around 20,500 FTEs by 2027 (Morrison, et al., 2024). Most of these new jobs will focus on constructing and installing wind farms. Key areas such as the Highlands and Dumfries and Galloway will need a large share of the workforce, but recruitment challenges already exist in these regions. Critical skills shortages include high-voltage engineers and wind turbine technicians. If these gaps are not filled, it could slow down the sector’s growth and reduce its economic and environmental benefits.

The solar sector faces similar challenges. Its workforce could need to grow from around 800 FTEs in 2023 to an estimated over 11,000 by 2030, with over 80% of these roles estimated to be related to construction, especially for large ground-mounted solar projects (Creamer et al, 2024). Solar projects will require key tradespeople, such as electricians, grid connection engineers, and high-voltage technicians. Many of the large solar installations will be in rural parts of Scotland, which makes workforce distribution a challenge.

Both sectors already have skilled workers, but they must attract and train more people to meet their installed capacity ambitions. While current training programmes can address some of these needs, there is a clear requirement to upskill and reskill workers from other sectors. Previous research (Morrison et al, 2024; Creamer et al, 2024) has shown that a large part of the additional workforce required for solar and onshore wind sectors will require education at Higher National Certificate, Higher National Diploma and degree levels. Furthermore, the industry strongly prefers trainees who have real-world experience in these sectors. As such, apprenticeships are expected to play a significant role in the delivery of the future skilled workforce.

Based on the findings of these studies, we argue that the timelines for intervention towards increased training provision are urgent. To illustrate, the onshore wind sector forecasts a peak of workforce demand as early as 2027, leaving only two academic years for intervention and subsequent training to be delivered.

This follow-on study focuses on the analysis of the existing and planned training provision, profiling its alignment with the industry needs, and exploring potential avenues for optimisation of training provision based on insights from sector stakeholders.

Conceptualisation of relevant training provision

The skills needed in the solar and onshore wind sectors can be divided into sector-specific, allied STEM, and other skills (Figure 2).

Sector-specific skills focus on the installation, maintenance, and safe operation of the unique infrastructure in each sector. For example, solar projects require expertise in setting up and maintaining solar panels, while wind projects demand skills in handling large wind turbines, often in challenging environments such as working at heights. Health and safety knowledge is critical in both sectors, as they each present different risks—solar work involves concerns like heat stress, while wind energy can involve working at height and operation of heavy equipment. Additionally, site design in both sectors requires highly specialised skills. Wind projects, for example, need knowledge of geology and land use to optimise turbine placement, whereas solar projects focus on efficient land use for arrays.

More detail on sector-specific skills and job roles can be found in the ClimateXChange publications by Creamer et al (2024) and Morrison et al (2024) (solar and onshore wind, respectively). These skills are often acquired through the apprenticeship routes, as well as first degrees and private training provision programmes.

Allied STEM skills include those adapted from broader disciplines such as civil, structural, mechanical and electrical engineering. These disciplines are essential for building and connecting renewable energy infrastructure to the grid. Engineers play a vital role in constructing foundations for wind turbines or solar supports and managing and balancing electrical systems. Further, skills from environmental sciences and logistics help ensure that projects comply with environmental regulations and manage supply chains effectively. Similar to sector-specific skills, allied STEM skills are acquired through apprenticeships, as well as first degrees and postgraduate training.

In addition to technical skills, other skills, such as finance, planning, and management expertise are critical for the success of renewable energy projects. These professionals may not have hands-on involvement in infrastructure development but are key in overseeing projects, securing funding, navigating regulations, and managing teams. Understanding the specifics of solar and wind energy is essential in these roles, as managers and leaders must handle complex projects, from permitting and financing to project delivery. These skills are a combination of theoretical sector understanding that could be achieved, for example, through first degree or postgraduate specialisation, in addition to extensive work experience in the sector. Albeit these skills are not the main focus of the current study, it is important to acknowledge their involvement in the sectoral skills ecosystem, and in particular in context of their position in career pathways for mid-career and senior professionals.

This report uses the framework outlined in Figure 2 for a comprehensive discussion of training provision that enables solar and onshore wind industries. This is in alignment with the precursor studies, which identified that the highest skilled workforce demands are likely to be within the allied sectors. This report discusses solar, onshore wind, and allied STEM skills training provision in parallel, as the skills needs across solar and onshore wind sectors have high levels of convergence. Any differences between the sectors are highlighted in the text and summarised in the Conclusions.

Figure 2. Conceptual framework of skill types relevant to solar and onshore wind industries.

Methodology

We carried out extensive desk based research, reviewing national and international policies and initiatives related to training provision for solar and onshore wind sectors and the renewable energy sector overall. This included the review of the precursor studies, literature regarding the EU Pact of Skills, International Energy Agency reports, and others.

Following this, we conducted a comprehensive landscape analysis of training provision in Scotland for solar, onshore wind, and other relevant STEM sectors. This process included profiling all training providers in Scotland’s higher and further education institutions, gathering course names and qualifications offered, and analysing course content to understand the themes and topics. We also mapped the geographic distribution of training provision sites to visualise the regional availability of skills provision.

To understand how the training provision aligns with industry needs, we reviewed national occupational standards (NOS) and explored future training initiatives. Additionally, we extracted and analysed student enrolment data from the Scottish Funding Council (SFC) to assess the number of students enrolled in relevant STEM disciplines and compared this with solar and onshore wind workforce demand forecasts from previous studies.

Our stakeholder engagement programme involved consulting a broad range of participants, including those from policy, training providers, supporting organisations, industry, and the supply chain (21 participants) between July and September 2024. Through semi-structured one-to-one interviews via Microsoft Teams, we gathered insights on how current policies affect training provision, the competition for talent, and talent retention. We also explored stakeholders’ views on the barriers and motivations individuals face when pursuing careers in solar and onshore wind sectors. These discussions helped us identify potential actions to address current and future skills gaps, as well as suggestions for improving the targeting, timing, and enhancement of training provisions. A complete list of the organisations we consulted is included in ‎Appendix A.

Key relevant training provision policy and initiatives

Scotland

Policy activity

In Scottish national policy, onshore wind and solar sectors are covered under the umbrella of green jobs / skills and renewables. Scotland’s National Strategy for Economic Transformation (The Scottish Government, 2022) places significant emphasis on building a skilled workforce to drive future economic prosperity. This publication outlines, in general terms, that the skills related to the net zero transition, including renewable energy, will be critical. It emphasises lifelong learning mechanisms such as continuous reskilling and upskilling as key to adapting to fast-paced technological changes. The Climate Emergency Skills Action Plan (CESAP) (Skills Development Scotland, 2020) is a document that outlines key initiatives to equip Scotland’s workforce for the transition to a net zero economy. The Green Jobs Workforce Academy was launched as a service aimed to help the workforce with training, upskilling, and job seeking in the emerging green sectors. The National Transition Training Fund (NTTF) was introduced in 2020 as a direct response to the economic impact of the Covid-19 pandemic. In its second and final year, the fund’s scope expanded and included a more significant emphasis on supporting individuals and employers in the transition to net zero. This followed a commitment within CESAP. Further, CESAP’s original publication indicated the ambition to launch the Green Jobs Skills Hub to provide insights into the skills needed over the next 25 years, working with businesses and educational institutions to ensure training aligns with the demand for green jobs

Additionally, CESAP indicates that sector-specific initiatives, such as the Energy Skills Alliance (now led by the Offshore Petroleum Industry Training Organisation OPITO) and Offshore Wind Skills Group, will map out skills requirements in renewable energy, such as hydrogen production and carbon capture. At a policy level, there is no equivalent regionally targeted working group aimed at solar or onshore wind.

CESAP set an ambition to work with educational institutions to realign curricula with industry needs and offer work-based learning to ensure individuals acquire the skills needed for Scotland’s green economy. Much of this work was carried out through Pathfinder activity under the remit of the Skills Alignment Assurance Group, now Shared Outcomes Assurance Group of the Scottish Government. Lastly, CESAP indicates that a place-based approach will target regional needs, with agencies like Highlands and Islands Enterprise leading efforts in rural areas to promote green job opportunities.

The CESAP Pathfinder Work Package 1 (Skills Development Scotland, 2023) aimed to understand the demand for skills driven by the transition to net zero and to map existing skills provision across apprenticeships, further education, higher education, upskilling, and reskilling. The report revealed that 27% (32,300) of college enrolments are in courses aligned with CESAP sectors. Additionally, around 16% of Scottish university graduates were working in a CESAP sector 15 months after graduation. In terms of apprenticeships, 29% (7,400) of Modern Apprenticeship (MA) starts and 38% (400) of Graduate Apprenticeship (GA) starts were in sectors aligned with CESAP. However, CESAP WP1 report indicates that there is evidence of leakage from this potential skills supply pipeline. Of the university graduates who entered a CESAP sector as their first destination, about 40% took jobs outside of Scotland. CESAP WP1 also highlighted the gap in knowledge of the future destinations of college students.

Future training provision initiatives in Scotland

Stakeholders across Scotland are engaging in a range of initiatives towards optimising future training provision for the whole renewables sector, many of which are targeted at offshore wind. We note that offshore wind skills are often directly applicable to onshore wind, and these are reviewed below. The Scottish Government, as part of its NSET strategy, prioritises a “Skilled Workforce” with a focus on future skills needs, including the net zero transition.

OPITO has introduced credit-rated qualifications in Hydrogen, Oil and Gas, and Wind Power to enhance workforce mobility across sectors. The Energy Skills Partnership (funded by Scottish Funding Council) supports key technical skills across Scotland’s colleges through various Training Networks. National Energy Skills Accelerator (NESA) has secured £1 million from the Just Transition Fund to pilot training programmes, including Performing Engineering Operations – Renewables, Electrical Systems for Renewable Energy, Project Management Fundamentals, and Energy Data Management.

Hosted by the North East Scotland College (NESCol) and funded by the Just Transition Fund, Energy Transition Zone/NESA is also developing an Energy Transition Skills Hub, which will include demonstration and teaching facilities for energy transition technologies and a state-of-the-art welding and fabrication academy. The Engineering Construction Industry Training Board has launched Energy Scholarships to address workforce shortages in roles such as Wind Transfer Technician and Energy Transfer Technician, with trainees receiving training in core engineering skills, new technologies, and digital competencies. RenewableUK and Energy & Utility Skills have partnered to create training and assessment standards for the UK’s renewable energy workforce, including national occupational standards (discussed below) and apprenticeship frameworks.

UK

In July 2024, the UK Government announced a mission to increase onshore wind development. This was marked by the launch of the Onshore Wind Industry Taskforce (UK Government, 2024). One of their key working groups is specifically focused on supply chains, skills and the workforce. The Taskforce will run for up to 6 months and culminate in the publication of a final report, setting out their commitments, and transition into the delivery body.

In May 2023, the UK Government launched the Solar Taskforce (UK Government, 2023) with terms of reference including skills governance for the solar sector. A ‘Draft Solar Roadmap’ was last discussed in the taskforce meeting in March 2024, and the final publication is pending.

European Union

In the European Union (EU), achieving the REPowerEU targets across all renewables sectors is predicted to create over 3.5 million jobs by 2030. In response to this rapid increase in STEM workforce demands, the EU has launched several initiatives to develop a skilled workforce for the renewable energy sector.

One of the flagship efforts as a part of the European Skills Agenda is the Pact for Skills (European Commission, 2020), aimed at upskilling and reskilling the workforce in various industries. One of the themes of the Pact of Skills is the Renewable Energy Ecosystem. This ecosystem is a series of strategic partnerships between the industry and policymakers to ensure sectoral cooperation for the development of skilled workforce in sufficient numbers. Examples of partnerships include Renewable Energy Skills Partnership, Large-Scale Partnership on the Digitalisation of the Energy Value Chain, and Skills Partnership for Offshore Renewable Energy. These initiatives are supported through consistent and sustained funding mechanisms such as Horizon Europe and Erasmus+ funding programmes. This capacity building is strengthened through international cooperation, facilitating the exchange of best practices and expertise, and harmonisation activities in training content.

Another relevant EU policy initiative is the BUILD UP Skills programme (European Climate Infrastructure and Environment Executive Agency, 2011), which has been active since 2011 and focuses on increasing skills in the construction sector, particularly for energy efficiency and renewable technologies. It provides national roadmaps to tackle skills shortages and works through EU funding programmes like Horizon 2020 and LIFE CET to support training for green energy jobs. This highlights that the EU is taking a broad approach to renewable energy workforce development and recognises the allied STEM skills role in it.

Overall, while these strategies aim to effectively transition workers and communities to renewable energy sectors, their success can be difficult to measure as the energy transition is ongoing. The long-term impact of workforce transition and reskilling is yet to be seen.

In addition to the skills governance, broader economic conditions, like market fluctuations and supply chain disruptions, also affect outcomes. The transition’s success ultimately relies on sustained political will, consistent funding, and strong collaboration among governments, industry, and communities.

Review of existing training provision

Targeted training programmes

List of targeted training provision

To identify targeted training provision that is relevant to solar and onshore wind sectors, we profiled course lists available on the websites of training providers (Scotland-based universities and colleges) and collated a list of courses that include renewable energy (general), wind, or solar in their title or public description. For private training provision, we carried out a Google search using keywords such as “Scotland solar PV training courses” and “Scotland onshore wind training courses” and profiled course lists available through private providers (remote training options were excluded from the analysis).

Our analysis of training provision identified a total of 57 courses relevant to solar and onshore wind sectors in Scottish colleges and universities being delivered in 2024/2025. We analysed the course content available in the public description on training providers’ websites and found:

• 23 courses that include content on renewable energy and energy systems (without specifying wind (onshore and offshore) or solar in the public description)
• 11 courses that include wind (onshore and offshore)- and solar-themed modules
• 5 courses that include solar-specific modules
• 18 courses that include wind-specific modules (onshore and offshore).

Figure 3 illustrates the levels of qualifications offered by the identified relevant courses. This data shows that most solar and wind sector courses are at postgraduate level specialism (25 total). This is in comparison to only 8 courses at the first-degree level, and two courses at SCQF L4. The highest number of targeted skills provision courses were hosted at the University of Strathclyde (10) and NESCol (7). The full list of courses identified as directly relevant to solar and onshore wind sectors is included in ‎Appendix B.

Figure 3. Levels of qualifications of courses targeted to solar and onshore wind sectors available through Scottish public education providers.

We note that the numbers outlined above are a high-level estimation of training provision for solar and wind. Other courses, particularly at BEng and BSc levels in electrical engineering and other allied sectors, might include further content relevant to solar and onshore wind. This analysis, therefore, focuses on courses where solar and/or onshore wind forms the major component of the course content.

In addition to training provision available through Scottish colleges and universities, we identified 110 short courses available through private training providers:

• Solar: 5
• Wind: 105 (specialist skill training, Global Wind Organisation (GWO) basic safety courses and other safety certifications).

These short courses are typically 1-6 days in duration and include certifications that are critical for safe working on solar and wind sites, as well as highly specialist technical skills and use of highly specialised equipment. The full list of identified relevant course private provision is included in ‎Appendix B, Table 2.

Thematic analysis of course content

We reviewed publicly available information on the contents of college and university courses identified as directly relevant to onshore wind and solar sectors and identified nine key thematic trends. All module names and themes are extracted from STEM course descriptions.

Theme 1: Fundamental engineering and electrical principles.

Module titles: Engineering Mathematics; Electrical & Mechanical Systems; Thermodynamics and Fluids; Electrical Engineering Principles; Core Maths; Electrical Systems; Fluid Mechanics & Thermodynamics.

Description: These modules provide the foundational engineering knowledge crucial for understanding and applying more advanced concepts in renewable energy. Mastery of these basic principles is essential for anyone entering the energy sector, as they underpin much of the work in system design, operation, and maintenance.

Theme 2: Renewable energy technologies and systems.

Module titles: Wind Turbine Technology; Solar Energy Systems; Marine and Wind Energy; Energy Conversion and Storage; Renewable Energy Integration to Grid; Wind, Solar, Hydro, and Marine Electricity Generation; Future Energy; Renewable Energy Technologies.

Description: This theme includes modules that focus on specific renewable energy technologies and systems. Students learn the principles, operations, and applications of various renewable energy sources, including wind and solar, as well as hydro, geothermal, and marine energy. These courses are most directly applicable to the onshore wind and solar sectors.

Theme 3: Power systems and grid integration.

Module titles: Electrical Power Systems; Power Electronics for Energy & Drive Control; High Voltage Technology & Electromagnetic Compatibility; Distributed Energy Resources and Smart Grids; Renewable Energy Integration to Grid; Power Systems Engineering and Economics; Power System Design, Operation & Protection.

Description: Modules under this theme cover the complexities of integrating renewable energy sources into existing power grids. Students are taught the technical and economic aspects of power systems, including high-voltage technology, power electronics, and grid management. This knowledge is essential for ensuring that renewable energy can be effectively and efficiently incorporated into the larger energy infrastructure.

Theme 4: Practical skills and hands-on experience.

Module titles: Assembling and Testing Fluid Power Systems; Operation and Maintenance of Wind Turbine Systems; Basic Hydraulics.

Description: Practical experience is a critical aspect of training in the renewable energy sector. These modules focus on hands-on learning, where students gain direct experience with the operation, maintenance, and troubleshooting of renewable energy systems. This practical knowledge is crucial for developing the skills needed to work effectively in the field.

Theme 5: Health, safety, and industry-specific certifications and standards.

Module titles: Health and Safety Passport (CCNSG); GWO BTT Course (Electrical, Mechanical, Hydraulics); ECITB Mechanical Joint Integrity Training; Solar and energy storage system design and installation modules recognised by Microgeneration Certification Scheme (MCS).

Description: Industry-specific certifications and skills are vital for professionals in the renewable energy sector. This theme includes modules that provide the necessary certifications and specialized training required by the industry. These qualifications are crucial for meeting industry standards and ensuring that professionals are fully prepared for their roles.

Theme 6: Sustainable energy and environmental impact.

Module titles: Basic Evaluation of the Impact of Energy Generation on the Environment; Sustainable Energy Management; Environmental Impact Assessment.

Description: Modules in this theme explore the environmental aspects of energy production and the importance of sustainability. Students learn about the environmental impacts of different energy sources, strategies for sustainable energy management, and how to reduce emissions and pollution. These modules are critical for understanding the broader environmental implications of energy projects.

Theme 7: Project management and strategic planning.

Module titles: Strategic Technology Management; Stakeholder Management and Governance; Project Management.

Description: Effective management and strategic planning are crucial for the successful execution of renewable energy projects. These modules equip students in STEM courses with the skills needed to manage complex projects, plan strategically, and navigate the economic and regulatory landscapes. This theme prepares students for leadership roles within the industry.

Theme 8: Innovation and advanced technologies.

Module titles: Data Analytics & AI for Energy Systems; 3D Printing and Inventor Programmable Logic Controllers (PLCs); Advanced Control Engineering; Digital Signal Processing Principles; Renewable Technology Commercialisation

Description: Innovation drives progress in renewable energy, and this theme covers the latest technologies and methodologies that are transforming the industry. Courses in this category focus on advanced technologies like AI, IoT, and programmable logic controllers, which are crucial for developing new solutions and improving existing systems in the renewable energy sector.

Theme 9: Energy economics and sustainability policy.

Module titles: The Economics of Community Wealth Building; Net Zero Society; Transition to Net Zero; Understanding Sustainability Discourses; Energy Resources & Policy

Description: This theme covers the economic, policy, and sustainability aspects of the energy sector. Modules in this category focus on the financial and regulatory frameworks that influence renewable energy projects, as well as the broader societal impacts of transitioning to a net-zero economy. Understanding these factors is essential for anyone involved in the strategic planning and implementation of renewable energy projects.

Based on these desk research findings, we conclude that the overall scope of current training courses has the potential to equip trainees with a wide range of skills suitable for various roles in the solar and onshore wind sectors, from technical and practical positions to environmental and project management. The courses also cover important areas like health and safety, policy, economics, and innovation, providing a solid foundation of knowledge for these industries. Stakeholders expressed a difference in opinion on the suitability of the content of current training provision for the industry. This is discussed in detail in Section ‎8.1.

Training provision alignment with industry needs

National Occupational Standards

National Occupational Standards (NOS) describe the skills, knowledge and understanding required to undertake a particular job to a nationally (UK-wide) recognised level of competence. NOS are proposed, developed and updated in response to industry needs. The process is usually led by the relevant industry skills association, that works with employers and sector experts to collectively refine NOS through a process of consultation. The NOS are then approved by UK government regulators to ensure that they meet industry requirements. NOS are the foundation for vocational qualifications, including apprenticeships. Learners are assessed against NOS to ensure that they have achieved the necessary competencies to be employed in that occupational role.

NOS are grouped into business sectors. There are 22 NOS that are grouped in the wind turbine sector, although only two are specific to wind turbines. There are 16 that are grouped in the solar PV sector, all but two of which are specific to solar PV. These NOS are listed in ‎Appendix C, Table 3. As of the time of the creation of this report, a review of the NOS is ongoing (Energy and Utility Skills, 2024).

Activity towards aligning curricula and industry needs

Based on intelligence received from industry, ESP previously created a Wind Training Network for the College sector. The Colleges were strategically located in areas where there was a demand for onshore wind turbine technicians. The network has grown from the original 3 colleges and now consists of 11 throughout Scotland to meet forecasted demands.

The curriculum content is co-created by colleges and industry and continues to evolve with direct industry input from companies such as Natural Power, that have sponsored wind turbine technician courses at Dumfries & Galloway College with direct routes to employment offered. This model is forecast to be rolled out to other areas where demand exists and can be duplicated and adapted by additional industry partners.

Colleges are collaborating with industry partners to deliver short technical courses for wind turbine technicians that include GWO BTT qualifications. The teaching materials are shared resources within the network and a collaborative approach to delivery is used. To date, the solar sector has not had the same level of interest, but as demand increases a similar college training network model can be implemented to increase capability and capacity to meet this growing demand, both strategically and sustainability. We note that there is minimal activity towards future training provision for the solar sector, especially in the context of large ground-mounted projects. One stakeholder noted that the minimal activity of ground-mounted projects in the planning pipeline has led to a lack of clear indication from the industry about its skills needs for these projects, making it challenging for training providers to respond.

Allied sector STEM skills provision

Overview

As illustrated in Figure 2, both onshore wind and solar sectors are further enabled by a skills base drawn from allied sectors. These skills are fundamentally rooted in non-energy-focused disciplines such as engineering (electrical, mechanical, civil, and structural), and applied disciplines such as construction, welding, electrical installation and others.

We have identified a total of 389 courses available through Scottish universities and colleges that are aligned with these topics (Figure 4). These courses are distinct from the courses identified in the section above. In this STEM training provision, we identified 10 Foundational Apprenticeships, 16 Modern Apprenticeships, 8 Graduate Apprenticeships and 14 pre-apprenticeship courses. Many of these apprenticeships are provided via the apprenticeship frameworks (listed in ‎Appendix D). Additionally, apprenticeships are also available through private companies, and typically these would not be advertised through training providers’ course lists and websites.

Figure 4. The number of courses in the allied sectors relevant to solar and onshore wind per provider.

Thematic analysis

A thematic analysis of the course content reveals broad provision across core engineering disciplines, particularly in structural, mechanical, civil, and electrical engineering. Key areas such as structural mechanics, geotechnical engineering, fluid mechanics, thermodynamics, and power electronics demonstrate comprehensive training in fundamental engineering topics. The curricula also place significant emphasis on computational techniques, with modules such as computer-aided engineering design, mathematical modelling, and finite element analysis providing students with essential design and analysis skills.

Environmental and sustainability topics are well-represented, with courses such as environmental engineering, water resource management, and sustainability, reflecting the growing importance of sustainable practices in engineering. Some of the curricula further include emerging technologies, such as artificial intelligence, machine learning, and Internet-of-Things as interdisciplinary data science fields. Additionally, modules in project management, risk management, and engineering innovation and management offer robust professional skills development, preparing students for leadership roles in managing engineering projects.

However, there are potential gaps. Emerging technologies, such as artificial intelligence, machine learning, and Internet-of-Things generally remain under-represented. The curricula could also benefit from expanded coverage of specific renewable energy subsectors, including solar and onshore wind; the current course content only mentions “wind” three times and “solar” two times.

In summary, while the course content provides a strong foundation in traditional and modern engineering disciplines, there is room to enhance the curricula by incorporating more emerging technologies and renewable energy topics. This would better prepare students for the evolving challenges of the engineering profession. It would also encourage students from engineering backgrounds to further specialise in solar and onshore wind sectors, particularly considering the lack of targeted solar and onshore wind coverage at undergraduate levels.

Geographic distribution of training provision

Locations of training provision

Research shows that future onshore wind farm developments will be in remote and rural areas of Scotland such as the Highland and parts of Dumfries and Galloway, resulting in a sharp increase in skills requirements in these geographies (Morrison et al, 2024). In comparison, commercial rooftop solar projects in Scotland are mainly based around densely populated areas, including the central belt, Borders, Dumfries and Galloway, the east, north-east, and Inverness. Ground-mounted solar projects will be primarily situated in rural areas like Aberdeenshire, Angus, Fife, and Tayside (Creamer et al, 2024), where there is ample land for larger systems.

We have created a map that shows where the targeted training provision is available (Figure 5). Most of these locations are aligned with the locations of higher and further education institutions, and it has been supplemented with locations of the private training provision company sites. It shows that the training provision is located within the central belt of Scotland, as well as Aberdeen and Inverness. There is an obvious disparity between the locations of training providers and the geographic regions where the solar and onshore wind workforce will be in the highest demand.

Figure 5. Geographic locations of Scottish training providers (colleges, universities, and private companies) offering courses relevant to solar and onshore wind sectors.

Stakeholder commentary on the development of local talent

Attraction, development, and retention of local talent pools in remote and rural areas was highlighted as an area of high concern by 9 of 21 stakeholders. The Highlands, in particular, faces substantial challenges in attracting and retaining local talent and developing a skilled regional workforce. Two regional stakeholders expressed an opinion that the Highlands is an emerging industrial cluster and predicted a sharp increase in demand for technical talent. This is an area of concern because the region has a rapidly ageing population (Highlands and Islands Enterprise, 2019).

“We don’t actually have enough (…) people for all the jobs that are going to be available.”

The temporary nature of jobs in the construction stages of solar and onshore wind projects further exacerbates the issue with the development of local talent. Construction and commissioning stages of projects in solar and onshore wind industries are marked by a sharp increase in workforce requirement. However, this demand is temporary as the construction stage of project development takes 2-3 years and is seasonal. As such, the industry is heavily dependent on a mobile skilled workforce. One stakeholder highlighted that the current reliance on bringing an external workforce to the region is, in effect, a barrier to the development of a stable, local talent pool for solar and onshore wind sectors. This is due to the fact that, from an industry perspective, skilled regional workforce development takes a significant investment of time that is not aligned with timelines of a typical project. From the workforce perspective, these temporary job roles might not serve as a basis for a life-long career and, therefore, make the sectors less attractive to new entrants.

“The reliance on transient workforce [means] there’s no real demand from developers to try and develop a workforce locally.”

In addition, two stakeholders indicated that the planned acceleration in onshore wind activity in England is a potential threat to maintaining a stable technical talent pool in Scotland. They explained that this acceleration is likely to drive a rapid increase in demand for skilled workers in England, where there is an anecdotal shortage of talent, prompting the industry to potentially draw from the Scottish workforce. Additionally, remuneration in England is perceived as higher, which could further incentivise talent migration.

“There is a concern that Scotland could lose a significant chunk of its skilled workforce to England.”

Addressing the future skilled workforce demands

Analysis of SFC data

To understand analyse the scale of skills being delivered against the projected future skilled workforce demands, we extracted data in relation to the total number of enrolments in all STEM-related courses identified as relevant to onshore wind and solar sectors. This was done in collaboration with the Scottish Funding Council.

The analysis of enrolment numbers on a course level was not possible as the data request could not be fulfilled in the timelines of this study. Therefore, the datasets discussed below are assessing combined annual enrolment numbers in both targeted and broader STEM training provision courses.

In the most recent available dataset (2021/2022), the total full person equivalent (FPE) enrolment in first degree, postgraduate taught and postgraduate research courses broadly identified as relevant to the sectors was 53,585 (Figure 6). The transferability of skills from these courses into solar and onshore wind is illustrated in ‎Appendix D, Table 5.

Figure 6. Number of enrolments (full person equivalents) in courses relevant to solar and onshore wind sectors in Scottish higher education institutions (2021/2022).

In the most recent available dataset (2022/2023) the total FPE enrolment in Scottish college courses that are engineering-focused and identified as relevant to solar and onshore wind and allied sectors was 14,890 (Figure 7).

Figure 7. Number of FPE enrolments in engineering courses identified as relevant to solar and onshore wind sectors in Scottish colleges (2022/2023).

To reiterate, previous studies have estimated the peak total workforce requirement for solar and onshore wind sectors as 11,000 and 20,500 respectively. The FPE numbers of the current training provision have been provided as an illustration of the training capacity of further and higher education institutions in Scotland in courses relevant to solar and onshore wind. However, it is critically important to note that the total FPE numbers illustrated in Figure 6 and Figure 7 above do not imply that Scotland’s skilled workforce needs are being addressed by the existing training provision. People from these courses enter a range of different industries, and this is explored further in Section ‎7.2. Additionally, annual FPE enrolments in the relevant courses do not equal the number of individuals completing the training, or the number of graduates that are entering the workforce. For example, the number of graduates in a four-year training programme could be 25% of the total FPE number (the 4^th year trainees).

Further, the data on the future destinations of students undergoing the training is fragmented, and this has already been flagged by CESAP Work Package 1 report (Skills Development Scotland, 2023). The recent SDS Apprentice Voice publication states that 71% of modern apprentices are still working for the employer with which they completed their modern apprenticeship 15 months after completion (SDS, 2024). Further research could explore the demographics, interests, and future career pathways of students in training to clarify the true number of entrants into the renewables sector and identify their subsector preferences.

Competition for talent

Due to the short timeline for meeting the 2030 installed capacity ambitions, addressing future skilled workforce demands in solar and onshore wind sectors will rely on cross-sector skills transfer. Interviews highlighted that one dominant sector that provides technically skilled talent to renewables, in particular onshore and offshore wind, is ex-service personnel (6 of 21 stakeholders).

Technically skilled talent is in high demand across many sectors, including other renewables (hydrogen and offshore wind), manufacturing, construction, the utility companies, and others. The competition for talent within the onshore wind and solar sectors is also fierce. As a consequence, workforce retention is an issue. This was highlighted as a critical challenge by 14 of 21 stakeholders consulted. Stakeholders highlight that a siloed approach to skilled workforce planning is a potential threat to the renewables sector as a whole.

“We’re competing with so many other sectors for the same skill sets… it’s a very competitive marketplace.”

In addition to problems in attracting talent from other industries, solar and onshore wind sectors face significant challenges in retaining skilled workers within their roles (14 of 21 stakeholders).

“We did go through a period… where there was very high turnover and lots of people leaving.”

Talent mobility is high, with workers often moving on to more lucrative or appealing opportunities after a short period. This disincentivises the industry to invest in workforce development via traditional pathways.

“The investment of spending three years training them [apprentices] [is significant]. At the end of it, a lot of them were literally staying in the role for six months, then looking to the next thing.”

The ageing workforce in parts of the solar and onshore wind sectors represents an additional challenge in training and developing talent.

“We’re losing a lot of our real experienced people that would normally mentor those coming in straight from uni… that’s where the struggle is.”

“The ageing workforce and impending retirements are exacerbating these challenges, as there are not enough experienced workers to mentor new entrants.”

The limited talent pool can result in solar and onshore wind companies headhunting suitably trained technical talent within their supply chains, with potentially detrimental consequences to these suppliers.

“When we’ve got good people… the developers come and use us as a recruitment location (..) clearly you can’t restrict people’s careers but (..) that’s a challenging area for us.”

The industry indicates that more innovative training mechanisms will be required to address the issues with training and retention, and these are discussed in Section 8.

Sector visibility and attractiveness

Due to the overall high demand for a technically skilled workforce, stakeholders highlighted that improving the visibility and attractiveness of the sector is a key element in ensuring that the future skills demands are met (11 of 21 stakeholders). They suggest that one strategy for ensuring optimal communication of sector attractiveness is by clearly describing the opportunities for life-long, diverse careers in these sectors. This can be achieved, for example, through the development of clear career pathway maps by building on the sectoral overlap matrix conceptualised in Figure 2, for example by illustrating career paths from technical roles into leadership, management, and planning (other skills).

“People want to see, okay, where can I go next? They want to see that career path… that’s where we need to be to attract people.”

“We need visibility of career pathways… there will be a lot more interest if there’s more visibility of how they can go about obtaining those roles.”

“The biggest challenge is that they don’t know how to progress within the sector.”

One stakeholder indicated that some companies in the onshore wind sector use career mapping internally as a tool for increasing employee retention within the organisation.

“We’re doing a lot of that internally now… developing a career path map so people can see the visibility of where they can go.”

One stakeholder, actively engaged with skilled individuals looking to transition to onshore renewable energy, indicated that the overall levels of visibility and clarity about the requirements and opportunities in solar and onshore wind are relatively low.

“They [skilled individuals seeking to transfer to renewables] need to understand the route to becoming a fully qualified electrician to get into solar installation.

For solar, we’re not seeing the volume of opportunities.

We’re talking a lot about the opportunities but they’re just not visible… we don’t see the wind turbine technician roles coming up that often.

Training provision gaps, barriers, and opportunities for improvement

Gaps and barriers

Gaps in training provision and alignment with industry needs

Stakeholders (16 of 21) consistently highlighted a significant gap between the content and capacity of existing training programs and the specific needs of the solar and onshore wind sectors. This gap is particularly evident in specialised, role-specific training, such as for wind turbine technicians and ground-mounted solar project development specialists. This is in contrast to the findings outlined in the Section ‎6 above, suggesting suboptimal levels of communication between the education providers and the industry in tailoring course content to the industry’s specific needs.

“We have generic degree courses in electrical engineering… it’s probably more the specialisms that we’re lacking just now.”

“There is no single qualification in solar. Generally, qualifications are part of a wider training provision.”

“I’ve got engineers at the moment that I need to get up-skilled in solar… the closest training course I can find is in the south of England.”

The mismatch between academic offerings and industry requirements creates challenges in producing a workforce that is ready to contribute effectively from day one. Stakeholders highlighted that training provision is reactive rather than proactive and does not anticipate the industry’s needs to meet the 2030 installed capacity ambitions.

“The qualifications available in Scotland are very generic… we need a much more work-ready solution so that when people come out of training, they have a much better insight into the specifics.”

“Most training providers at the moment are looking to provide training for current demand. And there’s no foresight as to what that’s going to look like in the next two, three years.”

A few stakeholders (3/21) indicated that skills provision for solar sector, and especially large-scale commercial rooftop and ground mounted solar, is limited in Scotland. This opinion is supported by the desk based research findings that showed that most solar-targeted training provision is specialised on domestic rooftop installations. There is a clear deficit in targeted training for the more complex and technically demanding aspects of large solar projects.

“Solar is lagging behind – all on awareness level, not competence-based… solar farms are less catered for.”

“There is very limited experience on these types of projects [large commercial and ground-mounted projects]”.

Barriers to increased training provision

A recurring theme that was highlighted by 15 of 21 stakeholders as a critical issue is the lack of targeted funding for training provision, which has become a significant barrier to expanding and adapting training programmes.

“Funding is the main issue… the absolute allocation to individual Modern Apprenticeships has not increased for 10 years.”

“Colleges are struggling to provide [relevant training provision] without external support.”

The financial constraints are compounded by the high costs of the necessary infrastructure and materials, leaving institutions to rely on limited general budgets.

“These are very expensive courses to cover in comparison with other courses.”

“My understanding is that there’s only one college right now that has the equipment to deliver high-voltage training.”

Stakeholders indicated the need for ring-fenced funding to support the development and delivery of courses that are specific to solar and onshore wind sectors. This has become particularly important after the termination of the National Transition Training Fund in 2022. One stakeholder further indicated the need for ringfenced funding for safety certifications to ensure that the skilled workforce is certified to work in solar and onshore wind environments.

“We have nothing… all of that ring-fenced funding is now gone.”

“The funding available is often for higher-level qualifications, but it doesn’t apply to safety tickets or other certifications, which can be a barrier.”

Stakeholder commentary on policy

Stakeholders (10 of the 21 consulted) highlighted that policy has a central role in market certainty and, therefore, future skills needs planning and training provision. Uncertainty, particularly concerning the future pipeline of projects, complicates long-term workforce planning. Companies are hesitant to invest in long-term workforce development initiatives without clearly understanding future project demand. At the conclusion of this study, the upcoming Energy Strategy and Just Transition Plan had not been published. Stakeholders highlighted that industry has interpreted this as a signal of market uncertainty, which by extension complicates their future workforce planning.

“We need confidence that there’s a long-term pipeline of projects… that gives us the green light to look at investment and ramping up the workforce.”

“If you’re recruiting an apprentice, you’re planning three or four years out… that’s challenging to do without certainty.”

Stakeholders also indicate that the skills governance and policy for solar and onshore wind currently lack certainty and strategic direction. This is in contrast to offshore wind skills governance, which was seen as substantially more mature, despite the lower levels of sector maturity compared to onshore wind. In addition, it was highlighted that the ongoing post-school education reform complicates future workforce development planning. In this context it is challenging for education providers to allocate resources to critical skills areas and delays the alignment of curricula with emerging industry needs, affecting the preparedness of trainees.

“The problem within my space at the moment is all our policy is up in the air… we’re waiting for (…) the funding review.”

“Without a clear directive from the government, the training provision will continue to be reactive rather than strategic.”

Overall, stakeholders called for a more strategic, top-level intervention from a policy perspective that would involve industry, training providers, and funding bodies.

Opportunities for enhancement

Modular and flexible training programs

The need for modular, flexible training programs that can quickly upskill individuals with relevant but incomplete experience is a recurring theme that was highlighted as the opportunity for training enhancement (14 of 21 stakeholders). These programs should be designed to provide targeted, condensed training that aligns with industry needs, allowing workers to become productive more quickly.

“They have the base skills and they just need a little top-up to actually enable them to move into the sector. We need to condense [training provision] into something intense, something that people can do in short courses.”

“If we [the industry] could fund modular type activities… that would really suit us.”

“We could take a more modular approach… train you to do [a certain task] and then upskill you as needed, but in the meantime, you’re productive much more quickly.”

The main idea behind modular training provision is to identify areas where a worker requires additional support while using their existing skills within the workforce. Two stakeholders described this process as skills “top-up”, as opposed to full retraining of already skilled workers that would remove them from the workforce for an extended period. This could be integrated into the existing training provision, with apprenticeships highlighted as one of the most important mechanisms for the delivery of a skilled workforce to the solar and onshore wind sectors.

“The perfect mix is where you have [modular training within] degree apprenticeships. They’re learning the fundamentals while getting operational experience.”

In addition, one stakeholder indicated that modular training provision could also support increased levels of training of trainers, expanding the skillset that can be passed on through existing training provision mechanisms. This highlights that the modular training provision could benefit different stakeholder groups and be synergistic for the development of skilled workforce.

Strategic collaboration between stakeholders

Effective workforce development in the renewable energy sector requires a coordinated effort between industry, government, educational institutions, and training providers. Stakeholders (18 of 21) consistently highlighted the need for improved communication and partnership that can lead to more effective training and recruitment efforts. This collaboration should focus on not only bringing together stakeholders from solar and onshore wind but also other relevant sectors.

“Employers need to work with training providers… to put together a training piece that’s going to assist [workforce that is looking to transfer] based on topping up their skills.”

“We just need to get that communication from industry… they [training providers] will absolutely ramp up and align their courses with it and we [a networking organisation] can support them to flex what they offer as well.”

“Government, industry, and training providers should be working more closely to develop a much more modular approach to the delivery of training.”

One stakeholder highlighted that, whilst the relevant people are “often in the same room…” they are “…speaking different languages”. This comment relates to the fact that policymakers, industry, education providers, and other stakeholders often tend to have different and occasionally conflicting priorities. As such, the solar and onshore wind sectors could benefit from more strategic and mediated conversations and relationship-building activities to ensure synergy between stakeholders.

Importance of practical training and on-the-job experience

There is a strong emphasis on the need for practical, hands-on experience in training programs. Many stakeholders (12 of 21) believe that current training programs are too theoretical and do not provide the real-world skills needed for success in the solar and onshore wind sectors.

“The practical element… is fairly limited, so we’re going to do more of that in-house now to meet the needs.”

“We’re still going to need months, if not years, of training them on our products… they have good general electrical engineering knowledge, but not the specifics.”

Two stakeholders indicated that, currently, qualifications alone do not guarantee competency to work in the sector.

“Just because someone is a qualified electrician, it doesn’t make them competent.”

Stakeholders also noted that the academic environment cannot prepare the future workforce for all required job roles in the industry, especially in mid-management. This relates to the previous insights associated with the ageing workforce; as the sector relies heavily on existing career professionals to upskill newcomers, mentorship and guidance must remain available to those entering the sector. This also applies to skilled workers transferring from other sectors to solar and onshore wind.

“The academic environment… doesn’t equip them as project managers. A lot of it realistically… where you get the real training is on the job.”

“We’ve been much more focused on… are they the right person culturally to fit the organisation… then we can train them from an experience point of view.”

Lessons learnt

The findings of our study suggest a series of key themes that could be used for future consideration in developing training provision for the onshore wind and solar sectors.

Although our analysis of current solar and wind sector courses found a theme of ‘practical skills and hands-on experience’ in the descriptions, industry stakeholders did not feel that this is sufficiently represented in the training available. Training providers need to ensure that the course content is relevant to industry needs, in particular regarding hands-on training and close collaboration with industry partners, including through apprenticeships. Access to internationally recognised, accredited training, such as GWO Health & Safety, should be prioritised to ensure that workers receive industry-standard qualifications.

Currently, most solar and wind sector courses are at postgraduate level of specialism. A shift towards a more flexible, modular approach to upskilling and reskilling the workforce is needed. This would allow individuals to tailor their training to specific needs rather than undergoing full retraining programmes. This has the potential to enable faster movement of individuals from training into the workforce which would benefit the industry.

Improved collaboration and communication between stakeholders is another critical lesson. The important role of government in creating clear market signals and strategic skills governance has been highlighted. Establishing more formal partnerships and regular cross-industry and education forums could help foster greater coordination and break down the siloed approach to workforce development. It would also benefit the SMEs in the solar and onshore wind sectors that cannot carry out substantial skills development programmes on their own.

To support the above points, there is a need to enhance and modernise existing funding mechanisms. This includes re-establishing targeted funding streams, encouraging industry investment in training, and exploring new funding models to support specialised programmes such as modular training options. In particular, there needs to be significant investment in practical infrastructure to support hands-on training.

This research highlights the centrality of allied STEM and other roles shared by both onshore wind and solar skills development. A siloed approach to STEM workforce planning is a threat as several industries are drawing from the same talent pool, resulting in competition with their vital supply chains. A more integrated perspective would consider the requirement for a STEM workforce across all infrastructure projects of national importance and overall installed capacity ambitions. A comprehensive map that details the scale, timelines, and workforce demands of major infrastructure projects has the potential to inform the total scale of skilled workforce needs and alleviate some concerns regarding the temporary nature of some job roles at times of peak demand. Such a map could be used as a signal of the availability of lifelong careers in these diverse sectors. Understanding the flow of skilled workforce amongst solar and onshore wind sectors and between other sectors will be vital to maximising skills and workforce potential.

Another suggestion for policy and the broader stakeholder ecosystem is the need to develop robust and compelling career pathways through comprehensive career mapping. Research is needed to outline career progression within the solar and onshore wind, as well as the broader renewable energy sector, and compare it with other major industries to create a comprehensive transferability framework. Identifying key roles, required skills, and potential career progression routes can provide clarity for professionals entering or transitioning within the sector, making it more attractive and accessible. This approach will be essential for addressing both recruitment and retention challenges.

Conclusions

In summary, current training provision has the potential to deliver the skilled workforce required for the solar and onshore wind sectors if it is strategically supported through policy certainty, targeted funding and changes in modes of training delivery. The need for intervention is urgent, as research indicates a peak in workforce demand as early as 2027 (Morrison, et al., 2024).

We have conceptualised the sectoral overlap of skills for the onshore wind and solar sectors (Figure 2). This demonstrates that although critical, specialised skills training provision is needed for solar and onshore wind separately, the majority of roles are shared by the sectors requiring allied STEM and other skills. We found that there are gaps for both sectors in specialised, role-specific training aligning to industry needs. However, siloed approaches for skills governance in solar and onshore wind could be counterproductive as the sectors compete for many of the same skillsets.

Allied STEM skills training provision in Scotland is extensive, with a significant number of students enrolling in relevant and transferable courses each year. These programmes equip trainees with foundational skills that can be applied across various sectors, including renewable energy. However, there is a lack of clarity regarding student destinations after completing these courses, making it difficult to track how many trainees are entering the solar and onshore wind sectors in Scotland. Stakeholder engagement highlighted that the onshore wind and solar sectors need to increase their job attractiveness in a highly competitive skills marketplace, including through increased visibility and clear career pathways.

Throughout this report, we have demonstrated the value of an integrated perspective, with the above conclusions being applicable to both sectors. However, our findings also suggest conclusions for the specific sectors, as set out below.

Sector specific conclusions: Onshore wind

Training provision for the onshore wind industry is available in Scotland but needs better alignment with the sector’s specific operational demands, especially with a stronger emphasis on practical, hands-on skills like wind turbine maintenance and site management. While there are few significant barriers preventing individuals from entering the industry, poor sector visibility is an issue. Industry leaders are keen to see training programmes that allow workers to quickly transition into the workforce, building on their existing knowledge while providing opportunities for continued upskilling. Modular training and “topping up” skills are considered vital to ensuring that workers can effectively meet the evolving needs of onshore wind projects and contribute to the industry’s success.

Sector specific conclusions: Solar

The solar industry in Scotland faces several challenges related to training and skills development. Currently, training provision is limited to domestic rooftop installations, which already require an electrical qualification. A major concern is Scotland’s lack of expertise in ground-mounted solar, which poses a potential threat to the sector’s development. There are no specialist courses available or training providers equipped to deliver the necessary skills. Skills governance for the solar sector is also lagging behind that of other renewable sectors, which further hinders the industry’s growth.

Like the onshore wind sector, the solar sector would greatly benefit from increased modular training provision to upskill workers quickly. However, training providers require a clear signal from the industry indicating a need for such courses. Addressing these gaps is essential for ensuring that the solar industry has a skilled workforce capable of supporting its growth.

Next steps

This study has identified the key barriers, opportunities and needs for intervention to increase training provision for solar and onshore wind sectors in Scotland. The next critical step is to develop a detailed, fast-paced action plan that engages all key stakeholders, including policymakers, industry representatives, training providers and potential talent pool representatives. Given the urgency of workforce demands and a projected peak of skills need as early as 2027, this action plan must establish clear and fast-paced timelines for intervention, with an aim to launch initiatives before the start of the next academic year (2025/2026). Coordinating this effort will be crucial to ensuring that Scotland can support the sectors’ rapid growth and deliver its renewable energy commitments.

References

Morrison, M., Beinarovica, J., Weir, I., Fagura, J., Schreib, S. (2023) ‘Workforce and skills requirements in Scotland’s onshore wind industry.’ Available at: https://www.climatexchange.org.uk/projects/workforce-and-skills-requirements-in-scotlands-onshore-wind-industry/ (Accessed: 25/09/2024).

Creamer, D., Beinarovica, J., Weir, I., Stodart, J., Romero, I. (2024) ‘Workforce and skills requirements in Scotland’s solar industry.’ Available at: https://www.climatexchange.org.uk/projects/workforce-and-skills-requirements-in-scotlands-solar-industry/ (Accessed: 25/09/2024).

Energy and Utility Skills (2024) National Occupational Standards (NOS) and Qualifications Review. Available at: https://www.euskills.co.uk/2024/08/20/national-occupational-standards-nos-and-qualifications-review/ (Accessed: 25/09/2024)

European Climate Infrastructure and Environment Executive Agency (2011) BUILD UP Skills – Upskilling and reskilling interventions for building decarbonisation. Available at: https://www.euro-access.eu/en/calls/1268/BUILD-UP-Skills–Upskilling-and-reskilling-interventions-for-building-decarbonisation#subtable4 (Accessed: 25/09/2024).

European Commission (2020) The Pact for Skills. Available at: https://pact-for-skills.ec.europa.eu/about_en (Accessed: 25/09/2024).

Government of India (2020) Skill Council for Green Jobs. Available at: https://sscgj.in/ (Accessed: 25/09/2024).

Highlands and Islands Enterprise (2019) Highlands and Islands Key statistics. Available at: https://www.hie.co.uk/media/6341/highlandsplusandplusislandspluskeyplusstatistics.pdf (Accessed: 24/09/2024)

India Corporate Sustainability and Responsibility (2023) Green Jobs Demand to Surge 15-20% Annually for a Decade. Available at: https://indiacsr.in/green-jobs-demand-to-surge-15-20-annually-for-a-decade-nlb-services/ (Accessed 24/09/2024)

International Energy Agency (2022) Skills Development and Inclusivity for Clean Energy Transitions. Available at: https://iea.blob.core.windows.net/assets/953c5393-2c5b-4746-bf8e-016332380221/Skillsdevelopmentandinclusivityforcleanenergytransitions.pdf (Accessed: 07/11/2024).

Morrison, M., Beinarovica, J., Weir, I., Fagura, J., Schreib, S. (2024) ‘Workforce and skills requirements in Scotland’s onshore wind industry’. Available at: https://www.climatexchange.org.uk/projects/workforce-and-skills-requirements-in-scotlands-onshore-wind-industry/ (Accessed: 25/09/2024).

Scottish Government (2022) Scotland’s National Strategy for Economic Transformation. Available at: https://www.gov.scot/publications/scotlands-national-strategy-economic-transformation/ (Accessed: 25/09/2024).

Skills Development Scotland (2020) Climate Emergency Skills Action Plan 2020-2025. Available at: https://www.skillsdevelopmentscotland.co.uk/media/w0ulewun/climate-emergency-skills-action-plan-2020-2025.pdf (Accessed: 25/09/2024).

Skills Development Scotland (2023) CESAP Pathfinder WP1 Executive Summary. Available at: https://www.skillsdevelopmentscotland.co.uk/media/el4fhf0m/cesap-pathfinder-wp1-executive-summary.pdf (Accessed: 25/09/2024).

Skills Development Scotland (2024) Apprentice Voice 2023 Annual Results. Available at: https://www.skillsdevelopmentscotland.co.uk/media/0twj3fpe/apprentice-voice-ma-kpis-2023.pdf (Accessed: 05/11/2024).

UK Government (2023) Solar Taskforce. Available at: https://www.gov.uk/government/groups/solar-taskforce (Accessed: 24/09/2024)

UK Government (2024) Onshore Wind Industry Taskforce. Available at: https://www.gov.uk/government/groups/onshore-wind-industry-taskforce (Accessed: 24/09/2024)

Appendices

List of consulted stakeholders

Skills Development Scotland

Universities Scotland

Solar Energy UK

Scottish Training Federation

Scottish Funding Council

Gensource

Engineering and Construction Industry Training Board

ITPEnergised

Scotland’s Electrical Trade Association (SELECT)

Career Transition Partnership

EVO Energy

Dumfries and Galloway College

Ayrshire College

NMIS/University of Strathclyde

NESCol/Energy Transition Skills Hub

NESCol/National Energy Skills Accelerator

Hitachi Energy

SSE Renewables

Scottish Power Renewables

Highland Council

Energy Skills Partnership (ESP)

Table 1. Training provision relevant to solar and onshore wind sectors available through Scottish colleges and universities in the academic year 2024/2025.

Table 2. Training provision relevant to solar and onshore wind sectors available through private providers.

Table 3: National Occupational Standards (NOS) that are relevant to onshore wind and solar PV.

* denotes NOS that are specific to onshore wind and/or solar PV. All others are more general, but still of relevance.

Table . List of Apprenticeship Frameworks identified as relevant for the broader STEM skills provision.

Table 5. Scottish university courses and their relative transferability to solar and onshore wind sector. This list is derived from SFC records where courses are ranked in red, amber, and green for their relative transferability to onshore wind and solar sector skills needs. The RAG rating was assigned through qualitative reasoning of the consultants following in-depth thematic analysis of the course content as discussed in Section ‎6.1.2. The full person equivalent data was provided by the Scottish Funding Council.

How to cite this publication: Beinaroviča, J., Creamer, D., Morrison, M., Brown, J., Knox, D. (2025) Training provision in Scotland’s onshore wind and solar industries, ClimateXChange. http://dx.doi.org/10.7488/era/5399

© The University of Edinburgh, 2025
Prepared by Optimat on behalf of ClimateXChange, The University of Edinburgh. All rights reserved.

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

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

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This research was a rapid review presenting and examining evidence relating to climate change and digital connectivity such as:

• whether investment in digital connectivity can support reductions of greenhouse gas (GHG) emissions and, if so, how
• examples of relevant policies and impacts
• the best options for assessing emissions from digital connectivity and services in Scotland
• key evidence gaps in these areas.

Summary of findings

The research team has found mixed evidence of the decarbonisation impact of digital connectivity and whether it contributes to adaptation and a just transition. The main findings, based on the literature reviewed are:

• The Information Communications Technology (ICT) sector is a source of GHG emissions.
• ICT technology and digitalisation reduce GHG emissions in other industries.  
• The GHG emissions associated with e-waste are of growing concern internationally.
• The indirect impact of ICT technologies can either lead to a net reduction in carbon emissions or to a net increase. Human behaviour plays a part in whether the indirect impacts on emissions are positive or negative.
• We are unable to say whether digital connectivity supports climate adaptation. With regard to a just transition, digital connectivity and ICT can have either a positive or a negative effect.

For more detailed information about the findings, 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.

Scotland recognises the significance of a place-based transition to net zero greenhouse gas emissions (GHG). The Climate Change (Scotland) Act 2009 places importance on the role of local authorities in achieving this target. Therefore, it is a priority for the Scottish Government to facilitate area-wide and locally-led efforts as part of a just transition to net zero.

Across the 32 local authorities in Scotland, 17 have set net zero targets specific to tackling territorial GHG emissions generated in their geographical area (from agriculture, buildings, industry, land use and land use change and forestry, transport and waste). This is in direct comparison to 26 local authorities that have set net zero targets to reduce their organisational GHG emissions.

This research examines local authority climate-relevant strategies and policies within them; the potential of these policies to reduce emissions if they were scaled to the national level; and the barriers that local authorities face in implementing these policies. The study developed a register of 69 climate change strategies across all 32 local authorities.

Main findings

• Local authorities are modelling exemplary action on climate change across many fronts through the benefit of deep-rooted relationships with local stakeholders and unparalleled knowledge of their area. However, the level of detail and methodological evidence presented in climate change strategies are often sparse, with many strategies failing to model the scale of impact on GHG emissions.
• The study identified two policy areas with the potential for major impact on territorial greenhouse gas emissions:
  • Nature-based solutions: a combination of individual policies to green derelict land, restore damaged peatland and afforestation.
  • Net zero transport: several climate policy initiatives such as active transport, decarbonisation of public transport and low-emission vehicle licences for taxis.

• The impact on Scotland’s national territorial emissions, should all local authorities adopt the leading policies, from nature-based solutions (5,497 ktCO₂e) and net zero transport (1,527 ktCO₂e) amounts to an estimated total potential reduction of 7,024 ktCO₂e by 2045. This is an indicative figure, illustrating the scale of change that could be possible.
• The Scottish Government have set a compelling ambition to closely support local authorities to develop locally owned and led climate action strategies to tackle territorial emissions. However, local authorities are limited by a lack of clarity on their roles and responsibilities, and by a lack of best practice guidance or frameworks across all the territorial emission categories. They face barriers including lack of data maturity, capacity, specialist skills, accountability and funding.

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.