Research completed March 2025

DOI: http://dx.doi.org/10.7488/era/6008

Executive summary

This project was commissioned to inform the Scottish Government on the potential for an interactive Energy Performance Certificate (EPC) in Scotland. It is proposed that interactivity could allow householders to better assess potential retrofit measures. This, in turn, may prompt households to undertake energy efficiency measures and switch to clean heat systems. This report will help inform whether it would be beneficial to incorporate data or functionality into the national EPC register to support potential EPC interactivity.

Key findings

Three levels of potential interactivity have been identified for the Scottish Government to consider implementing in relation to EPCs:

1. Simple interaction, where both (i) no new user data and (ii) no integration with a calculation engine are required. Users could choose between customised or simplified views of EPC data. Click-through links signposting to further information could also be included (e.g. about measures, funding, further advice services).
2. Medium interaction, where (i) no new user data is required, but (ii) integration with a calculation engine is required. Users could see updated calculations based on already-completed as well as potential retrofit measures. Fuel costs could be updated in line with recent trends.
3. Detailed interaction, where customised user behaviour and occupancy inputs could update outputs via integration with an enhanced calculation engine (medium interaction functions also included). Users could personalise a range of inputs for which default values are normally applied in an EPC calculation.

The EPC outputs likely to be most useful to households are costs: household energy running costs, running cost savings, and the capital cost of various retrofit measures. The extent to which these outputs may be customised varies, as does the complexity of implementation. For example, household energy running costs could be updated by simply considering the latest fuel prices. Or, it could be tailored by updating one or more of the following variables: fuel prices, occupancy, heating temperature set point, heating patterns, or the number of baths or showers taken per day.

However, customising more variables may not necessarily make the outputs more representative, since the reliability of obtaining some of those inputs may be quite low. At any level of customisation, it will be necessary to inform tool users that outputs are ultimately estimates. Actual energy use and costs will inevitably be influenced by annual climate severity, changing fuel prices, and changes in household circumstances.

There are a number of existing tools that already deliver energy advice to households. These have varying levels of interactivity and customisation. In response to user testing and feedback, many offer relatively limited customisation. Circumstantially, this supports the reasoning that a modest spectrum of customisation may be the limit to which users are prepared to use such tools.

Limited evidence was identified of a direct link between the provision of customised information and households being prompted to retrofit. However, various literature sources quoting both professionals and typical consumers call for interactivity and customisation of EPCs. There is also relatable evidence that the provision of tailored information to households can prompt behavioural change. Offering households some level of interactivity alongside a traditional ‘static’ EPC could therefore be beneficial. Unfortunately, no direct evidence was found to support whether simpler or more detailed interaction is more likely to prompt households to retrofit.

Considerations for implementation

If the Scottish Government is minded to pursue an interactive tool, there are various options. It may commission its own interactive tool, or alternatively, it may look to use or adapt an existing tool to deliver a similar service.

The Scottish Government will also need to consider how best to integrate net zero policy ambitions in the implementation of any tool outputs or recommendations.

Providing sufficient interaction/ customisation for end users to feel that outputs are relevant to them is likely to be most important. The ability to update information from a ‘static’ EPC to reflect changes that have already taken place will likely be key. Furthermore, the ability to toggle retrofit measures will give users a sense of choice and control.

While a relatively simple implementation may suit the majority of potential users, a minority of users may see particular benefit in tailoring a wider range of input variables. If ‘detailed interactivity’ were implemented (as defined above), then customised views/ functions for different user groups may help simplify the user experience.

Glossary / Abbreviations table

Introduction

This project considers how an interactive Energy Performance Certificate (EPC) user interface may help to increase public uptake of energy efficiency and clean heating options in homes.

There could be an opportunity to integrate data that would support the development of an interactive EPC user interface when assessing the future needs of the national EPC register in Scotland. A system that enables the public to better assess energy efficiency and clean heat options may be expected to increase uptake of these measures. However, the Scottish Government needs to understand the likely benefits and limitations of such an interactive user interface before it makes decisions on changes to the EPC register.

Background and research scope

The focus of this report is on domestic EPCs. An EPC assessment combines findings from a physical survey of a building with standardised assumptions on how it is used. EPCs therefore provide an ‘asset performance assessment’ that allows homes to be compared to others elsewhere in the country. This is regardless of whether they are different sizes, specifications, or have different systems and/or use patterns. They are accompanied by a Recommendations Report. This provides examples of measures that may improve the efficiency of the home and make savings, intended to encourage homeowners to take action. Recommendations are presented in a set sequence that follows a fabric-first approach, with renewable energy sources considered last. EPCs are therefore an important source of information for homeowners and buyers to inform decision making.

However, the presentation of recommendations and savings means users are not aware of the impacts of implementing measures out of sequence. Also, EPCs do not provide information regarding potential options for switching to cleaner heat systems where properties are currently served by another fuel type. EPCs as therefore not necessarily aligned with the aims of the Scottish Government Heat in Buildings Strategy with regard to clean heat systems. Savings predictions reflect the standardised assumptions made in the EPC calculation in relation to occupancy and heating patterns. This makes the EPC less helpful when a homeowner wants to understand the benefits and savings they may experience according to their own circumstances. Offering users a level of interactivity may allow benefits of different potential improvement measures to be expressed. This can lead to more tailored recommendations and thus may better support users to act on them. There could therefore be value in a traditional ‘static’ public EPC for regulatory compliance, and an interactive interface to provide customisation for homeowners.

The scope of the research was therefore to identify the data inputs and outputs that may be relevant to an interactive EPC and consider how data inputs may be sourced.

The focus was on interactivity that would allow homeowners to input contextual information about how they use their home; essentially customising aspects of the EPC calculation that would otherwise use standardised assumptions, e.g. occupancy, heating patterns and temperatures. It was assumed that data obtained from an original EPC building survey would not fundamentally be challenged, e.g. floor areas, construction types. However, it is acknowledged that homeowners may wish to update information where retrofit works had already taken place since the EPC was carried out. For example, when new insulation has been installed or when energy systems have been upgraded or changed. Note that implications of the General Data Protection Regulation (GDPR) on interactive EPCs were deemed beyond the scope of this study.

Further, we sought evidence to understand the benefits and limitations that an interactive EPC interface may provide, to demonstrate whether user interactivity has led to increased uptake of retrofit measures. Our research explored a number of existing tools that offer a level of interactivity with EPC-like outputs. These were primarily targeted at homeowners (i.e. covering domestic/ residential properties), although portfolio-level tools were also briefly considered. The research also involved a desk-based literature review.

Data inputs and outputs for potential EPC interactivity

EPC review

Domestic EPCs for Scotland are produced using the UK Government’s Standard Assessment Procedure (SAP) implemented in approved software tools. For existing dwellings, it is recognised that detailed construction information is unlikely to be available. A ‘reduced data’ version of SAP (RdSAP) is therefore used, which makes assumptions about the construction based on age, etc. A selection of the inputs and outputs of the resulting calculation are held centrally in the Scottish Government’s EPC Register. Note, however, that not all intermediary outputs from the RdSAP calculation steps are held on the Register.

EPC outputs

We reviewed the outputs reported on a current Scottish domestic EPC (as at 2024). Those that may be relevant to end users making decisions on energy efficiency and clean heat measures were identified, as noted below. Further metrics proposed in the Scottish Government consultation on EPC reform were also considered for insight into potential future changes.

• Energy Efficiency Rating (EER) (also known as the ‘SAP score’; Proposed to be called ‘Energy Cost Rating’ following EPC reform)
• Environmental Impact Rating (EIR)
• Primary energy indicator (kWh/m²year)
• Running costs (£ for 3 years)
• Savings (from potential recommended measures) (£ for 3 years)
• Savings per recommended measure (£ for 3 years)
• Recommended measures capital cost (£)
• Emissions from the home (kgCO₂/m²/year)
• Space heating demand (kWh/year)
• Water heating demand (kWh/year)
• Heat Retention Rating (proposed for EPC reform; expected to be similar to Space heating demand metric)
• Total energy use (proposed for EPC reform; expected to be similar to the calculation for primary energy indicator, but for delivered energy, i.e. without primary energy multiplier)

Dependent inputs

We then interrogated the underlying RdSAP calculation methodology^[1] to identify the key inputs used to calculate the identified outputs. All outputs are derived from numerous inputs and calculation steps, with the exception of ‘Recommended measures capital costs’, which are simply quoted reference values. Inputs that offer the potential for contextual customisation relevant to particular occupant behaviour/use are noted below.

• Fuel prices and standing charges
• Capital costs for retrofit measures
• Number of occupants
• Number of baths or showers taken per day
• Living room comfort temperature set point
• Heating pattern on/off times (for a normal day and an alternative day, e.g. weekend)
• External temperature (from regional climate information)

Ease of implementation

We made a qualitative assessment of the ease with which the above EPC outputs may be customised via calculation. Extensive customisation of an RdSAP calculation using occupancy parameters was implemented in the Green Deal Occupancy Assessment (GDOA) tool^[2]. Since the GDOA tool functionality already exists^[3], customisation of a number of contextual/ user inputs could be relatively easily facilitated in an RdSAP 2012 calculation. The following ‘ease of implementation’ ranking was therefore applied to the EPC outputs identified above:

• High ease: Where an output already held on the Scottish EPC register could be adapted via a straightforward side calculation (i.e. where no RdSAP calculation engine would be required to re-model the impact).
• Medium ease: Where the output could be updated by implementing aspects of the GDOA as part of a new RdSAP calculation, using data held on the EPC register.
• Low ease: Where customisation of metrics has not previously been implemented in an RdSAP calculation, and therefore more work would be required to implement.

Note: In assigning this ‘ease’ hierarchy, it is assumed that the data held in the non-public version of the Scottish EPC register aligns with the import requirements of an RdSAP 2012 calculation. This appears likely to be the case based on summary information provided by the Scottish Government for this study. However, this would need to be verified in order to validate the recommendations of this study.

Table 1 shows the qualitative ‘ease of implementation’ ranking for customised EPC outputs.

The table refers to the SAP Product Characteristics Database (PCDB). The PCDB holds reference data for mechanical systems, which is used in SAP and RdSAP calculations. It also holds fuel prices and estimates for the capital costs of measures that are used in RdSAP calculations. Fuel prices are updated in the PCDB every 6 months but they are fixed in an EPC at the time of its issue. Capital cost of measures are only updated when a new version of the RdSAP methodology is released.

Currently, the EPC register does not store fuel use totals from the RdSAP calculation, although it is an intermediary calculated value that underpins many subsequent metrics. It is understood that this data is absent from both the public and non-public versions of the register held by the Scottish Government. It follows that even relatively simple-seeming amendments to EPC outputs, e.g. updating fuel prices, would require an RdSAP calculation to be re-run. Two scenarios have been presented in Table 1 for ‘Recommended measures capital cost’. Scenario A is assigned a ‘high’ ease of implementation, while Scenario B is assigned a ‘low’ ease of implementation. The measures costs applied to an EPC are generic and not tailored to the property (e.g. according to property dimensions, or similar). Scenario A assumes this is still the case but an alternative, updated source for measures costs could be referenced by an interactive tool. Customised retrofit measures costs were not a function that was implemented in the GDOA. Therefore, if such a customisation function were desired, this scenario would have a low ease of implementation.

Table 1: Ranking of current and proposed EPC outputs according to their anticipated
ease of customisation

End user value of existing EPC outputs

The EPC outputs identified in 5.1.1 were qualitatively assessed for their likely importance to end users in retrofit decision making. Discussions were held with Retrofit Coordinators at the National Energy Foundation, who directly engage with households on energy retrofit. Their feedback is supported in various studies (including National Retrofit Hub (NRH), (2024), Which? (2024), Jones (2022), and Bančič, Vetršek and Podjed (2021)) that have examined which metrics different end users find or would find valuable when considering home upgrades. In Table 2, the EPC outputs have again been assigned a ranking, this time indicating their expected usefulness to end users. Notes provide supporting rationale for each ranking.

Table 2: Ranking of EPC outputs according to their likely importance to end users
in retrofit decision making

Simple cost-based metrics are more likely to be easily understood by consumers and are therefore more likely to contribute to retrofit decision making. This includes running costs and cost savings from potential retrofit measures. Energy assessors, consultants or other professionals in the sector may see value in the other metrics, but feedback suggests these are of less use to households. Furthermore, the concept of carbon emissions is identified in the above reference sources as not being tangible for most consumers, despite national policy striving for ‘net zero’.

Review of existing interactive home energy advice tools

Numerous tools are available, beyond a traditional RdSAP calculation, that offer EPC-type outputs to users with a level of interactivity/customisation. A selection of these tools were reviewed for this study to consider the possible forms a Scottish EPC user interface could take. Tools were identified using web searches and the knowledge of the research team. Criteria for inclusion included:

• A domestic/ housing focus
• An aspect of interactivity/customisation
• Outputs similar in nature to those on an EPC (e.g. energy use, cost, retrofit recommendations)

Six tools were then selected for more detailed investigation. Selection criteria included:

• Sufficient information available so they could be assessed for this research
• Tools offering differing levels of interactivity/customisation
• Limiting duplication of tools created by a single organisation, unless they offered something distinctly different from one another
• Inclusion of a commercial/ portfolio assessment tool

We assessed outputs provided by each tool and the customisable inputs they request from users. These are summarised in Table 5 and Table 6 respectively, in Appendix A, alongside the outputs and inputs discussed earlier for EPCs. For the latter, the potential inputs are those of the RdSAP Green Deal Occupancy Assessment, which is taken as a baseline for calculation customisation potential.

It is apparent that many consumer-facing tools are based on a limited number of calculation engines. The Energy Saving Trust (EST) engine and the Parity Projects/ Core Logic engine appear to be popular options underpinning branded tools. These front-end tools may offer slight variations in presentation or user functionality, but they draw on the same foundational data and calculation approach. All tools rely on an underlying RdSAP calculation engine to generate outputs. However, they do not offer the full functionality of RdSAP to be customised, instead utilising many assumptions and generalisations. Most tools use at least some EPC data (from the EPC register) to pre-populate information for calculations.

Tools typically offer one or more of the following levels of interactivity/customisation:

• Ability to toggle potential retrofit measures on or off and assess impacts/ benefits
• Ability to make simple updates to property data (compared to that held on EPC), e.g. if insulation or new windows have been installed. Some also ask if there is space to facilitate renewable energy systems
• Ability to provide basic contextual or occupancy information (some tools will typically progress with assumptions if users do not wish to provide customised information e.g., number of occupants, typical living room set point temperature, when people are typically at home)
• Ability to provide more detailed contextual or occupancy information (again, some tools will typically progress with assumptions if users do not wish to provide customise information e.g., number of baths and showers taken per week, actual energy use totals from bills)

Many tools also offer further interactivity that does not relate to the calculations process but provides users with additional information. Examples include click-through links providing:

• Specific information about retrofit measures
• Information about potential funding or finance options
• Links to trusted trades or advisory services (e.g., TrustMark, one-stop-shops)
• Links to professional whole house retrofit plan or Retrofit Coordination services

It was noted in discussions with NEF that consumers often feedback that they are not confident translating a retrofit plan into action. There is apparently often distrust of trades/ contractors. Qualitative information such as that above may help households build confidence to take plans forward.

None of the consumer-facing tools reviewed allows for customisation to the same extent as the GDOA tool. The EST/ Home Energy Scotland tool provided the widest range of user customisation options. From discussions with a selection of tool owners, their user testing and feedback has identified a need for relative simplicity. It is assumed that this reasoning has also been applied to other tools, as they often offer similar functionality.

All the reviewed tools focus on the outputs expected to be of most value to consumers, as noted in section 5.1.4. These include running costs, cost savings from measures and the expected capital cost of retrofit measures. Most tools also report associated carbon emissions. However, despite this alignment in key outputs, the extent to which inputs can be customised varies across tools. It may be expected that outputs based on more extensive customisation will be more representative of a user’s actual circumstances. It is relatively unlikely that users will have an appreciation of this though, since they may only ever interact with one tool. All tools evidently have their place in the market, though it is very difficult to accurately assess their respective ‘success’ (i.e. the extent to which they encourage homeowners to undertake retrofit). Some commentary is offered in relation to specific tools below.

A consistent aspect of functionality offered across all tools is the ability to update whether some building elements have already been enhanced. They all also offer the option to select different potential retrofit measures to form a tailored retrofit plan. It should be noted however, that these outputs are not equivalent to a ‘whole house retrofit plan’ as defined by the PAS 2035 framework (BSI, 2023). These aspects of interactivity can help consumers consider the impacts of certain retrofit options and thus they can provide a useful step beyond a traditional ‘static’ EPC. It may be inferred that these are the aspects of most value to consumers, and there is perhaps less focus on perceived ‘accuracy’ of further customisation. Some aspects of the reviewed tools are discussed in more detail below.

UK Government ‘Find ways to save energy’ tool

This tool is owned by the Department for Energy Security and Net Zero (DESNZ). It uses an RdSAP engine hosted by BRE that implements selected parts of the GDOA. It includes default assumptions being made for parts of the GDOA that users are not asked to customise. DESNZ have indicated in discussions that user testing and consumer feedback has shaped the current functionality of the tool. For example, an earlier release of the tool included more customisation questions. However, these were removed as they led to high levels of user ‘drop out’ associated with those questions (i.e. users exited the online tool without completing beyond certain questions). Additional feedback suggests that a minority of users (estimated ~10%) would like more detail than the tool currently offers. DESNZ are exploring options for potential future updates.

EST engine backed tools

Three different tools were reviewed that utilise EST’s calculation engine:

• Home energy check (branded as Home Energy Scotland)
• Go renewable tool, developed with the Microgeneration Certification Scheme (MCS)
• The Snugg Plan Builder (an example with a custom branded front end)

Each offers slightly different functionality and very different user interfaces. For example, the Home Energy Scotland tool does not directly link with the EPC register. However, users are encouraged to obtain their EPC information (from the register if not readily available) to aid answering questions. The Go renewable tool, as the name suggests, focusses on advising on renewable energy systems. It also gives recommendations on basic fabric efficiency measures that should ideally be carried out in conjunction with certain renewables.

Go Renewable and the Snugg Plan Builder each introduce some novel output metrics. Go Renewable offers a ‘heating system running cost metric’, which allows different heating system options to be directly compared. The Snugg tool features a metric on the potential income from a PV system (based on the Smart Export Guarantee). It also estimates a potential increase in property value increase resulting from installing retrofit measures. ‘Savings’ metrics may not motivate landlords or people that do not expect to stay in a home that long. However, metrics linked to property value may be an alternative motivator for such users.

Parity Project/ Core Logic ‘EcoRefurb’ tool

EcoRefurb is part of the Core Logic ‘Plan Builder’ suite of tools. It is an example of a branded front-end tool that uses the underlying Core Logic engine. According to the developers, user testing shaped the development of both inputs and outputs within the tool. One key aspect they identified as important was the provision more customised measure recommendation costs for users. Very few users apparently fed back that they would like to get into more detail in the initial assessment. More detail may be customised in the Plan Builder tool Core Logic provide to Retrofit Coordinators (similar to that in the GDOA) however, this was not reviewed during this study.

IRT ‘DREam’ stock assessment tool

Stock-level assessment tools were also considered during this study, although it is acknowledged that householders are not their target end users. The IRT tool is one such example intended for housing providers^[4] (e.g. social landlords) to assess potential retrofit options at a stock level. Customisation typically focuses on filling data gaps where individual property surveys or EPCs have not been conducted. They also allow updated information to be input, based on maintenance records for example, to provide updated energy data for properties. A key feature of the DREam tool is that it integrates a map function and can overlay areas by index of multiple deprivation for example. It also provides comparisons of funding options that may support housing providers to deliver area based retrofit schemes. Understandably, occupancy-based customisation is not a focus of tools such as this. However, the property information updating and measures toggling functions are evidently important interactive outputs for the tool’s target audience.

Discussion: Levels of interactivity

Three broad levels of interactivity (simple, medium and detailed) are identified here for potential application to the existing EPC, for consideration by the Scottish Government. These levels reflect the functionality of the calculation tools that underpin an EPC and the capabilities of other existing interactive ‘energy advice’ tools that have been reviewed. This also assumes that data from the non-public version of the Scottish EPC register is sufficient to recreate a new RdSAP 2012 calculation for a dwelling.

Simple interaction

This is characterised as interaction that requires no new user data to be input and no calculation engine. Examples of potential functionality could include:

• The ability to provide switchable, customised or simplified views for data for different types of user via an online interface. For example, more detailed EPC information could be accessible by professionals, while only key outputs may be required by households, with options to switch between views.
• Click-through links signposting users to further information – such as details about measures or funding, links to trusted tradespeople or advisory services, etc.

Medium interaction

At this level, no new data inputs are required from users, but an RdSAP calculation engine would be needed to support provision of increased interactivity. Examples of potential functionality could include:

• Allowing users to select their own potential retrofit measures, providing tailored cost savings for different retrofit approaches or combinations of measures (rather than a fixed sequence as per the current EPC methodology).
• Enabling potential updates to property information where retrofit measures have already been installed.
• Incorporating updated fuel costs sourced from the latest version of the PCDB.

Detailed interaction

Here it is assumed that a calculation engine is capable of incorporating customised user inputs to inform updated outputs. (All of the medium interaction functions above should also be possible at this level.) Examples of potential customisation could include updating with:

• Actual household fuel costs and standing charges.
• Actual number of occupants.
• Actual living room temperature set points, heating schedules.
• Actual number of baths or showers taken per day by household.

Section 6 discusses the ease with which data inputs may be sourced. It highlights that there may be a sliding scale of complexity of customisation at the ‘detailed’ level.

Implications related to RdSAP 10 and the Home Energy Model (HEM)

Data currently held on the Scottish EPC Register will have been created using the RdSAP 2012 software version. Reusing this data to re-run a new RdSAP calculation will therefore be more straightforward with an RdSAP 2012 engine. This is subject to confirmation that data held in the non-public version of the register is an appropriate format.

An updated version of the software, RdSAP 10, is currently in development. The ‘full’ version of SAP 10 has been in use since 2022 for newly built homes. It introduces several updates, related to heat pumps and introduces battery storage into calculations.

Translation of existing EPC Register data (created under RdSAP 2012) for use with a newer SAP engine such as the proposed RdSAP 10 would be more complex. Additional assumptions would need to be added alongside the original data from the EPC register. Furthermore, there is also no GDOA implementation in RdSAP 10 (i.e. customisation of occupancy parameters), so a further exercise would be required to replicate this functionality. However, moving to an RdSAP 10 engine would bring any new tool in line with the most current calculations, based on updated research.

The Home Energy Model (HEM) is a new calculation methodology that will eventually replace SAP and RdSAP. A key change in this approach is that calculations will be performed with much finer time resolution. While existing SAP and RdSAP calculations consider a monthly timestep, HEM utilises a 30-minute resolution. This is expected to better-represent heating demands, energy storage and demand flexibility potential for example.

HEM is based on a fundamentally different underpinning architecture compared to SAP. It will use ‘wrappers’ to assess different use cases, with each wrapper defining inputs and outputs that are processed by the core HEM model. One such wrapper will support the Future Homes Standard (FHS). In this context, key changes to modelling assumptions are expected compared to SAP. For example, assumptions about occupancy being linked to floor area (as in SAP) to being based on the number of bedrooms in a property. These changes reflect evolving consumer behaviours and systems operation patterns, highlighting further divergence from the assumptions used in SAP 10.

HEM will undoubtedly offer additional functionality compared to SAP, along with the ability to assess certain technologies more effectively due to its increased granularity. Some innovators, such as City Science and Furbnow, are already attempting to link existing home energy assessments to HEM. Both have undertaken projects in this space with the support of Innovate UK. However, during presentations at the Innovate UK ‘Net Zero Heat Open Day’ both organisations reported that additional input data, gathered from surveys and/or monitoring, is needed to achieve this (UKRI, 2024). That being the case, it seems unlikely that data from the existing EPC register could readily be aligned with HEM. Exploring the effort likely required in achieving this was beyond the scope of this study.

Data collection/ input methods and limitations

Review of potential data sources

A number of potentially customisable data inputs were identified in section 5.1.2.^[5] This section explores ways such data may be sourced and/ or physically input into a tool (e.g., automated versus manual methods). While several theoretical options have been explored, the likelihood of some such information being available/ usable short term is low.

Table 7 in Appendix A gives an overview of relevant data input options that were identified during this study. Each input method was qualitatively assessed, based on the research team’s judgement, on a ‘high, medium, or low’ scale against the following parameters:

• The ease of data input for the user
• Likely reliability of the information
• Likelihood of an information source to be available in the short-to-medium term

The rankings were assigned a score (High = 3, Medium = 2, Low = 1). These were summed to provide an overall current ‘readiness’ metric (scored out of 9).

Manual data entry approaches

Manual approaches rely on households obtaining data from existing sources (such as energy bills) or simply recalling their comfort/ heating preferences (e.g. temperature set points and heating patterns). Users will also readily know how many occupants are typically in the house.

The current readiness score of some manual inputs reflects the potential risk of reduced reliability when households need to consider typical conditions over a whole year. For example, if users never adjust temperature set points on their thermostats, reliability of temperature inputs may be high. This may also be the case if they never adjust programmed heating patterns. However, users are unlikely to take account of incidental day-to-day or seasonal adjustments made outside the normal programming. It is also unlikely that households would consistently track their average number of baths and showers per day for a whole year. A best estimate based on typical patterns seems far more likely. Reliability of some inputs may therefore be low when it depends on household recollection rather than on actual recorded data.

Automated data entry approaches

Automated methods range from updating information from the PCDB through to potentially obtaining data from internet of things smart devices. Fuel prices and standing charges could be taken from the most recent version of the PCDB. There are artificial intelligence (AI) tools that exist (generally intended for businesses) that can extract information from digital energy bills. However, for individual households, such tools are unlikely to be warranted since the information could manually be obtained relatively easily. Smart sensors include motion detectors (inferring occupancy), shower sensors, thermostats and programmers. All of these devices may theoretically be able to track and log conditions and output household data.

Note that there is currently no function or API (Application Programming Interface) to import external data sources into an RdSAP calculation. SAP calculations call on data held in the PCDB, but this database is updated periodically and not accessed ‘live’. The automated transfer of data is therefore an aspect that would need to be developed, if such functionality were desired. Subsequently, any proprietary sources of data (e.g. from consumer apps) would need to be collated and formatted accordingly to feed into SAP. It is assumed that users would be unlikely to manually process such data themselves if it were not automatically formatted and exported.

Automated methods therefore tend to score less highly than equivalent manual methods in the combined readiness metric. They score highly with respect to the ease of data input for the user and many provide inherently reliable data. However, they score low on the short-term likelihood for such automated functionality to be available. Fuel prices updated automatically from the PCDB are assumed to be less reliable than actual data from household bills due to averaging. However, the relative ease of implementing such an update still gives a high overall readiness score (8 out of 9).

Discussion of external temperature data

The RdSAP calculation utilises climate data broken down into 21 UK regions. These include assumptions for monthly average external temperatures. It is possible that some users may question whether the granularity of these climate zones is representative of their local conditions. However, it is quite likely that most users would not have the necessary awareness to challenge the relative accuracy of the climate data used.

Monthly temperature data is available from the MET office (the source of the current RdSAP climate data) at a resolution of 2km. This is a far higher resolution than the 21 UK regions. The format is essentially the same as is used in an RdSAP calculation. However, it would require reasonable effort (and signposting) for users to obtain this data manually and enter it into a user interface. As discussed above for automated methods, there is currently no function for new data to be imported into RdSAP. This would need to be specifically developed to automate the input of new, more granular external temperature data.

Something of potential interest to users and the Scottish Government is that the MET Office also provide ‘future climate scenario’ data sets. If incorporated into an RdSAP calculation, it would be possible to see the impact of changing climate conditions on key outputs and recommendations. Granularity varies depending on the type of climate predictions offered. For example, monthly average temperature predictions against the highest emission scenario (RCP8.5) are projected at a 12km scale. Import of such data to RdSAP would face the same challenges as other updated MET Office data noted above.

Varying interactivity options for outputs

Table 3 shows the outputs assessed as being of highest importance to consumers^[6] alongside the relevant potentially customisable inputs. ‘Emissions from the home’ is also included, since the policy focus of retrofit is ultimately on achieving net zero emissions. Both a ‘medium interaction’ and ‘detailed interaction’ version (as per section 5.3) is included where such options exist. Note the medium interaction would require a SAP calculation engine but no new user input, instead using updated information from the PCDB or elsewhere. The highest ‘readiness’ levels determined for each of the data inputs is presented in the table.

Table 3: Highest ‘readiness level’ of data inputs that may be customised for
EPC outputs (at varying levels of interaction)

While some outputs in Table 3 have several potentially customisable inputs, not all may necessarily be customised. The example tools reviewed in section 5.2 implement different customisable inputs yet deliver essentially equivalent outputs. The inputs therefore represent a sliding scale of potential customisation.

Users may find it quite easy to customise one or two inputs with a high-scoring readiness indicator. Meanwhile, a more bespoke version of the same outputs may be possible, but the ease with which the data may be reliably obtained may be lower. This creates a potential risk of dubious accuracy; an output may seem to be accurate since it is based on multiple user customised variables. However, those variable values themselves may be inaccurate or unreliable, thus reducing the overall representativeness of the output. A sensitivity analysis on this phenomenon is unfortunately beyond the scope of this present study.

Absolute accuracy may not in fact be so relevant for an interactive tool intended to aid retrofit decision making. Pre- and post- retrofit energy performance of homes is relative; after all, many variables out of a user’s control influence energy consumption and cost over a given year. (e.g. external climate, energy price changes, varying household needs.) Providing sufficient interaction/ customisation for end users to feel that outputs are relevant to them is likely to be most important. The ability to update information from a ‘static’ EPC to reflect changes that have already taken place will likely be key. The ability to toggle retrofit measures selection will give users a sense of choice and control. Other input variables may be of more or less interest to users depending on how far they feel their behaviours are from ‘typical’. Households that align with these national trends may see little variation in customised calculations compared to default calculations. It is only when household characteristics are quite different from national trends that it may make notable differences to retrofit recommendations.

Evidence of intended outcomes

We looked for evidence that directly linked the use of interactive tools to the initiation of retrofit measures. Information was also sought on whether different types of interaction or customisation were more likely to prompt household decision making. A desk-based evidence review sought information from academic articles and grey literature. A selection of search terms were initially used, as detailed in Appendix B. These were expanded upon as other terms and concepts were identified in the reviewed sources.

In addition, advisors from NEF provided general feedback based on their experiences of directly supporting consumers with retrofit projects and administering grants.

Feedback related to the use of existing interactive energy advice tools, such as those discussed earlier, was also explored. This was primarily via online sources, though interviews were conducted with tool developers where possible. DESNZ (as owners of the UK Government ‘Find ways to save energy’ tool) and Core Logic (EcoRefurb tool) provided direct feedback on their respective tools.

The evidence review was widened to ‘relatable activities’ when it became clear that limited information was available on interactive tools and retrofit. Relatable activities were defined as those in which the provision of some form of customised information prompted behavioural change. The scope was limited to households and housing, and to at least energy-related behaviours, if not retrofit specifically. This broader search was not exhaustive but was intended to provide indicative context relevant to the primary concept.

Review of literature

Many sources suggest there is a need for interactivity and customisation of EPCs, with inference that this could promote the uptake of retrofit measures. However, no evidence was identified in the literature review to confirm that interactive tools would, or have directly, prompted retrofit actions. Nor did the literature review indicate what level of interaction or customisation might be more likely to prompt households to undertake retrofit.

Several EU research projects have explored ways that EPCs could be improved to better-serve various end uses (e.g. U-CERT, D2EPC, X-Tendo, CHRONICLE, EDYCE, Smart living EPC). U-CERT produced an extensive series of recommendations for EPCs (Bančič, Vetršek, and Podjed, 2021). This followed interviews and focus groups with different types of potential EPC users across 11 participating EU countries. Some recommendations related to improved granularity of calculations and reducing the ‘performance gap’ by using dynamic simulation and the use of measured data. However, many specifically focus on helping users better understanding energy use and prompting retrofit action. Several of these are also recognised in other sources (discussed below).

Example recommendations include:

• Focus on cost-based metrics, as these are most tangible for users
• Offer interactivity to make the information relevant to a user’s own circumstances and context
• Provide different views tailored to the needs and knowledge levels of various users:
• (a) non-professional users, for buying and selling properties, for energy management, and for retrofit recommendations.
• (b) Professionals and more advanced users with more detail and technically specific data.
• Digitalisation offers the potential for a ‘modular’ approach from basic to expert with options according to user interests
• Explain the context of assumptions, so users understand if their patterns are likely to be different to what is assumed

Various studies have investigated the extent to which current static EPCs motivate users to retrofit. A recent study by Which? (2024) indicated that EPCs are rarely used to inform renovation decisions. Users instead rely on advice from builders or their intuition. The study suggests that the current format of EPCs does not effectively encourage homeowners carry out energy efficient home improvements, nor does it meaningfully guide their choice of measures.

The D2EPC research study found that less than 5% of end users were motivated to retrofit because of their EPC (Panteli and Duri, 2021). At least half of those surveyed were also not convinced that their EPC accurately represented their building’s energy efficiency. A Barclays/ Ipsos survey (Barclays, 2023) suggests that over half of homeowners do not feel confident making homes more energy efficient. A further study (Hiscox, 2018) indicates that a third of those surveyed renovated to keep up with current trends rather than for functional reasons.

The U-CERT and Which? studies indicate there is a need to update an EPC so they can still be relevant if some changes/ improvements are made. Otherwise they are readily obsolete (Bančič, Vetršek, and Podjed, 2021; Which?, 2024). The Which? study also states that EPC recommendations are too rigid, presented in a specific order rather than tailored to household priorities and budgets. This need for greater flexibility was echoed in discussions with Retrofit Coordinators at NEF who work directly with consumers. They observe that many households are favouring less disruptive, less risky technologies, rather than deep energy efficiency retrofit measures. App-linked technologies also gaining popularity, raising people’s interest in things like heat pumps, PV and battery storage.

This supports a case for savings forecasting across a flexible sequence of measures, rather than the pre-defined order used in EPCs. However, NEF note the importance of linked guidance (i.e. simple interactivity) on risks and implications of implementing measures outside a validated sequence. They advocate the role of Retrofit Coordinators in developing whole house retrofit plans to help households avoid unintended consequences. The U-CERT recommendations similarly stress the value of contextual information and guidance alongside an EPC (Bančič, Vetršek, and Podjed, 2021).

The majority of reviewed literature generally supported the concept of interactivity for EPCs. However, in the experience of innovators ‘Furbnow’ (UKRI, 2024), some users were not confident in entering property data in EPC tools. For this study, we recognise that there is a risk that too much complexity could deter users. Simpler interactivity may therefore be preferable.

Review of relatable activities

The literature review was widened to ‘relatable activities’ based on the research team’s experiences in the energy and retrofit sector. This included exploring links between interactive outputs and intended behavioural change on retrofit plans, smart meters and green finance (for retrofit). Reviewing these relatable activities provided some evidence that customised and/ or interactive information can prompt intended behavioural change among households.

Retrofit plans

Retrofit plans are bespoke reports intended to guide owners on how to retrofit their homes. These follow the principle of considering the individual context of a retrofit, (e.g. user influence), i.e. they include customised recommendations. Building Passport trials (including renovation plans) have been in place for a number of years in several countries and have also been the subject of previous ClimateXChange research (Small-Warner & Sinclair, 2022). Despite this, no quantitative evidence was found that their implementation increases retrofit uptake. Only circumstantial evidence of ‘intent’ from end users was given, suggesting likely future uptake of measures. In other words, it is not currently possible to directly link the implementation of renovation plans in Building Passports to a measurable increase in retrofit.

In the iBroad project trial, the majority of respondents agreed that a renovation roadmap enables and motivates them to undertake retrofit measures (Irish Green Building Council (IGBC), 2020). Similarly, 63% of experts surveyed for the follow-up iBroad2EPC project believed that tool would motivate homeowners to renovate (Mellwig, Maiwald, and Pehnt, 2024).

It was observed that renovation plans implemented in EU countries generally follow national policy by prioritising energy efficiency recommendations before renewable energy measures (Enefirst, no date). This is similar to the current approach taken in UK EPCs. As implemented, these plans do not necessarily provide the flexibility called for in many discussions of EPC reform. They are however, tailored to personal circumstances based on assessor expertise.

Smart meters

Smart meters serve multiple purposes. These include accurate billing, supporting the use of flexible tariffs, and improving visibility of the granularity of energy use at a local and national level. Alongside in-home displays, smart meters provide information that can help households to understand and potentially reduce their energy use.

A study for Smart Energy GB (Populus, 2019) found that consumers with smart meters report a higher number of energy saving activities than non-users. These activities increased over time with continued active smart meter use. There were also increased levels of behavioural change, such as buying more efficient appliances and implementing energy saving habits. Smart meters also enabled people to take part in flexibility and Time of Use activities to save money. These benefits are attributed to the in-home display showing energy use in near real time. This tailored, real-time information was reported to aid users in identifying energy usage and making more informed decisions to reduce usage.

These findings are supported by several other studies, some of which highlight the importance of displaying data in terms of cost to make it more relatable to users. (Darby et al, 2015, National Centre for Social Research (NatCen), 2022, Marshall Cross et al, 2019).

Detailed data (i.e., at appliance level information) was found to be most useful and persuasive for end users. For example, Scottish Power data analysis of interactive app users suggests a 5% energy saving compared to non-users. This is attributed to the more detailed breakdown of energy use, which raises awareness among householders and prompts action (Scottish Power, no date).

These findings support the concept that the provision of bespoke, time-relevant and cost-based data can encourage behavioural change. This may be likened to the customisation of an EPC providing up to date cost saving measures recommendations. Similar behavioural motivations may therefore be experienced as has been seen with smart meters.

Green finance mechanisms

Green finance (i.e., lending that supports environmentally-friendly activities) has been briefly explored as a behavioural incentive for retrofit. Data from Knight Frank for example supports the view that users value properties with higher EPC ratings (Knight, 2022). As such, retrofit measures that improve an EPC could increase property value. While this does not directly relate to interactivity, introducing interactivity or customised elements to EPCs that link recommendations to potential increases in property value could help promote behavioural change towards retrofit. This may be particularly motivating for landlords or individuals that do not expect to stay in a property long term, for whom typical ‘savings’-based motivators may be of little interest. The Snugg/ EST tool mentioned in section 5.2.2 includes an assessment on post retrofit property value.

Review of existing tools

No direct evidence was found to indicate whether simpler versus more detailed interaction and customisation is more likely to prompt households to undertake retrofit. As discussed earlier, many of the existing advice tools reviewed for this study offer limited level of customisation features. Circumstantially, this supports the idea that a modest spectrum of interactivity and customisation may be sufficient to motivate consumers. It is noteworthy that many consumer-targeted energy advice tools ultimately refer users to a professional service, where more detail can be explored. Such tools therefore appear to be primarily intended as a mechanism to motivate households onto the next step on a retrofit journey.

Direct feedback was obtained via interview by DESNZ regarding the UK Government’s ‘Find ways to save energy’ tool. This is only an advice tool and is not formal linked to any retrofit delivery schemes. As such, DESNZ are unable to track a ‘success rate’ for how many users of the tool convert to actually implementing a retrofit.

Additional feedback was gathered by interview with product developers Core Logic regarding their EcoRefurb tool. Core Logic advise that it is a free online tool to give consumers an idea of the retrofit options that may be suitable for their home. Users are then encouraged to develop a more detailed Whole House Plan with a Retrofit Coordinator. The developer reports that around 50% of users that submit a plan via the free tool go on to obtain a Whole House Plan. They consider this a good uptake rate.

By the time that consumers engage with professionals, they are reportedly well-informed and have a clear idea of the improvements they wish to pursue. However, from this point, it can sometimes take a year or more for households to instigate measures. A similar observation was also shared by NEF, who noted that households may need to save up for works or may choose to align with wider home renovation activities.

Conclusions and recommendations

Our research finds that cost-based metrics are most tangible and motivating to end users. The following EPC outputs are likely to be the most worthwhile focus for any proposed interactivity or customisation:

• Running costs
• Running cost savings
• Retrofit measures capital costs

We identified three potential levels of interactivity (Table 4) for the Scottish Government to consider implementing in relation to EPCs.

Table 4: Potential levels of interactivity for EPCs

We did not find direct evidence to support whether simpler versus more detailed interaction or customisation is more likely to prompt households to retrofit. However, there appears to be significant demand from professionals and consumers for interactivity and customisation of EPCs. Additionally, there is relatable evidence from the use of smart meters, retrofit plans and from green lending that the provision of tailored information to households can prompt behavioural change. Offering households some level of interactivity alongside a traditional ‘static’ EPC could be beneficial.

All pf the tools reviewed in this study include the ability to update and toggle retrofit measures, addressing the call for increased flexibility in EPCs identified in the literature review. User testing and feedback from energy advice tool providers suggest that most existing tools offer a relatively limited degree of customisation. Circumstantially, this supports the notion that a modest level of customisation may represent the upper limit to what users are willing to engage with.

Many existing energy advice tools operate at the medium interaction level. There can be a sliding scale of complexity of customisation at the ‘detailed’ level. Importantly, greater customisation of inputs does not necessarily make the outputs more accurate, since confidence in various data inputs may be variable. The option to offer various customised or switchable views or functions for different users may help simplify an interactive EPC experience if necessary. For example, users could switch between ‘simple’ and ‘medium’ interaction views for users that do not wish to enter detailed personalised inputs.

At any level of customisation, it will be necessary to inform tool users that outputs are ultimately estimates. Actual energy use and costs will inevitably be influenced by a range of other factors e.g. annual climate severity, changing fuel prices, and changes in household circumstances, etc.

The implementation process may be more complicated depending on what version of SAP is targeted for use. RdSAP 2012 is the version used to create the EPCs currently on the register. Translation of existing EPC register data to use the newer RdSAP 10 engine would be more complex. It would also require some assumptions to be added alongside the original data from the EPC register. A move to align to RdSAP 10 would however bring the tool in line with a number of updated calculation assumptions. Moreover, the effort required to align with a HEM calculation has not been explored, though it is noted that the mechanics of HEM fundamentally differ from SAP. Considerable effort would be required by numerous parties to unlock the automated input of data i.e. an RdSAP tool provider (working on behalf of the Scottish Government) and proprietary software or app providers collecting user data.

Existing tools already deliver energy advice to households with varying degrees of interactivity and customisation. Therefore, rather than developing a new tool, the Scottish Government could consider whether a branded or adapted version of an existing tool may deliver a suitable service.

Opportunities and challenges of implementation

Interactive functionality has the potential to support the promotion of both energy efficiency measures and clean heating systems. There is clear scope to improve alignment with current Scottish Government policies on clean heat, particularly when compared to the limitations with existing EPCs. Currently, EPCs do not provide running cost or savings estimates for fuels types other than those currently used in the home. However, this functionality could potentially be introduced.

The Scottish Government will need to consider whether, and, how it wishes to support recommendations that involve the continued use of fossil-based systems. An interface could, in theory, be designed to present recommendations prioritised either for carbon savings or cost savings. Some of the tools reviewed for this study allow users to express their preference, which can subsequently influence the prioritisation of retrofit measures. The Scottish Government could choose to prioritise carbon savings in order to align with its ‘net zero’ policy. However, this may not align with the approach preferred by all households. Consideration of potential fuel poverty risks will also be needed.

Clean heat measures implemented in isolation from wider energy efficiency measures could lead to increased running costs for some users. However, the likelihood of this is reduced where heat pumps are adopted and appropriately installed (EST, no date, National Energy Association (NEA), 2022). Any changes in running costs should be clearly reflected in tool outputs to support informed decision making. However, this would stray from the current approach to retrofit recommendations on an existing EPC. These are prioritised ‘fabric-first’, and only those that would provide running cost savings are included.

Providing flexibility in how retrofit measures are recommended on an interactive EPC would likely be welcomed by users. However, this flexibility also introduces risks if retrofit measures are actioned without due consideration of wider property factors. For example, improving insulation and airtightness without adequate ventilation can lead to moisture build-up, which poses health risks due to damp and mould, and in some cases, structural damage (May and Griffiths, 2015). To mitigate this, linked guidance would be advisable where users have unlimited flexibility when selecting retrofit options. This would help prevent unintended consequences.

It is noted that the Scottish Government’s consultation for the Heat in Buildings Bill proposed a Heat and Energy Efficiency Technical Suitability Assessment (HEETSA) (Scottish Government, 2023). This is expected to offer a more tailored assessment of the suitability of retrofit than a standard EPC. If implemented, a HEETSA could play a role in reducing the risk of adverse outcomes from retrofit measures.

The provision of guidance and signposting (i.e., simple interactivity) may be a more user preferable and transparent alternative to policy-driven functionality. Users may lose trust in a tool if they feel the outputs are not aligned with their personal motivations. Conversely, they may value clear and candid advice, including information about potential risks, to support informed decision making.

Consideration may also need to be given to the skills and capacity of the retrofit delivery sector when designing an interactive tool. If the service proves very successful, an upturn in retrofit measures may be expected, which may outstrip local supply. Anonymously tracking the types of recommendations typically taken through to household retrofit plans could help identify potential capacity gaps within the delivery sector.

References

(All web references last accessed 18 February 2025)

Bančič, D., Vetršek, J. and Podjed, D. (2021) D2.3 Report on users’ perception on EPC scheme in U-CERT partner countries. Available at: https://u-certproject.eu/media/filer_public/
3c/30/3c30cb41-517f-4625-811c-0381eb745caa/u-cert_d23.pdf

Barclays. (2023) Homeowners put off energy efficiency upgrades due to misconceptions about cost and installation time. Available at: https://home.barclays/insights-old/2023/07/homeowners-put-off-energy-efficiency-upgrades-due-to-misconcepti/
#:~:text=Misconceptions%20around%20the%20cost%20and,homes%2C%20according%20to%20new%20research.

BRE. (2014) The Government’s Standard Assessment Procedure for Energy Rating of Dwellings 2012 edition. RdSAP 2012 version 9.92: Occupancy Assessment version Mar 2014. Published on behalf of DECC by BRE. Available at: https://files.bregroup.com/bre-co-uk-file-library-copy/filelibrary/SAP/2012/OccupancyAssessment2014.pdf

BRE. (2019) The Government’s Standard Assessment Procedure for Energy Rating of Dwellings 2012 edition. RdSAP 2012 version 9.94. Published on behalf of DECC by BRE. Available at: https://bregroup.com/documents/d/bre-group/rdsap_2012_9-94-20-09-2019

BSI. (2023) PAS 2035:2023. Retrofitting dwellings for improved energy efficiency – Specification and guidance. Published on behalf of DESNZ by British Standards Institution.

Darby, S. et al (2015) Smart Metering Early Learning Project: Synthesis report. Department of Energy & Climate Change (DECC). Available at: https://assets.publishing.service.gov.uk/
media/5a818dd0e5274a2e8ab549c7/8_Synthesis_FINAL_25feb15.pdf

Enefirst. (no date) Building logbook – Woningpas: Exploiting efficiency potential in buildings through a digital building file. Available at: https://enefirst.eu/wp-content/uploads/
12_BUILDING-LOGBOOK-WONINGPAS.pdf

Energy Saving Trust (EST). (no date) Heat pumps: how they work, costs and savings. Available at: https://energysavingtrust.org.uk/advice/in-depth-guide-to-heat-pumps/

Hiscox. (2018) Hiscox Renovations and Extensions Report 2018. Available at: https://www.hiscox.co.uk/sites/uk/files/documents/2018-03/Hiscox_renovations
_extensions_report_2018.pdf

Irish Green Building Council (IGBC). (2020) Introducing building renovation passports in Ireland: Feasibility study. Available at: https://www.igbc.ie/wp-content/uploads/2020/09/
Introducing-BRP-In-Ireland-Feasibility-Study.pdf

Jones, C. (2022) Optimised Retrofit: Engaging with residents; lessons learnt. Available at: https://chcymru.org.uk/cms-assets/documents/ORP_Engaging-with-residents_Lessons-Learnt_Sero_Grasshopper.pdf.

Knight, O. (2022) Improving your EPC rating could increase your home’s value by up to 20%. Available at: https://www.knightfrank.com/research/article/2022-10-11-improving-your-epc-rating-could-increase-your-homes-value-by-up-to-20

Marshall Cross, E. et al (2019) Smart meter benefits. Cost savings households could make within a smart energy future. A Delta-EE Viewpoint, February 2019. Available at: https://press.smartenergygb.org/media/otklgpuf/smart-meter-benefits-cost-savings-for-households-february-2019.pdf

Mellwig, P., Maiwald, F. and Pehnt, M. (2024) iBRoad2EPC field test results. Available at: https://ibroad2epc.eu/?sdm_process_download=1&download_id=13627

National Centre for Social Research (NatCen) (2022) Research into maximising the benefits of smart metering for consumers. Qualitative research with smart meter consumers. Available at: https://natcen.ac.uk/sites/default/files/2023-02/Research-into-maximising-the-benefits-of-smart-metering-for-consumers-Qualitative-research-with-smart-meter-consumers.pdf

National Energy Action (NEA). (2022) Making heat pumps work for fuel-poor households. Common challenges and top tips for overcoming them. Available at: https://www.nea.
org.uk/wp-content/uploads/2023/02/Installing-heat-pumps-for-fuel-poor-households-landscape.pdf

National Retrofit Hub (2024) The future of energy performance certificates: A roadmap for change. Available at https://nationalretrofithub.org.uk/knowledge-hub/epc-reform/
#headline-531-936

Panteli, C. and Duri, M (2021) D1.2: Next-generation EPC’s user and stakeholder requirements & market needs v1. Available at: https://www.d2epc.eu/en/
Project%20Results%20%20Documents/D1.2.pdf

Populus. (2019) Smart meters and energy usage: a survey of energy behaviour among those who have had a smart meter, and those who have yet to get one. Available at: https://press.
smartenergygb.org/media/s3ujojpg/smart-meters-and-energy-usage-may-2019.pdf

Scottish Government. (2023) Delivering Net Zero for Scotland’s Buildings. A Consultation on proposals for a Heat in Buildings Bill. Available at: https://www.gov.scot/publications/
delivering-net-zero-scotlands-buildings-consultation-proposals-heat-buildings-bill/

Scottish Power. (no date) Energy insights. Available at: https://www.scottishpower.co.uk/
energy-insights

Small-Warner, K. and Sinclair, C. (2022) Green Building Passports: a review for

Scotland. Published by BRE on behalf of ClimateXChange. Available at: https://www.climatexchange.org.uk/wp-content/uploads/2023/09/cxc-green-building-passports-january-2022.pdf

May, N. and Griffiths. N. (2015) Planning responsible retrofit of traditional buildings. Sustainable Traditional Buildings Alliance (STBA). Available at: https://stbauk.org/wp-content/uploads/2020/08/STBA-planning_responsible_retrofit.pdf

UKRI. (2024) Net Zero Heat Open Day. Session 1: Rapid Assessment of Building Fabric Performance. Recordings available at: https://iuk-business-connect.org.uk/events/net-zero-heat-open-day/

Which? (2024) Transforming EPCs: Consumer Research Insights and Recommendations. Available at https://www.which.co.uk/policy-and-insight/article/transforming-epcs-consumer-research-insights-and-recommendations-a7mQM8Z6Pnpj

Appendices

1. : Supporting data

Table 5: Summary of outputs of existing interactive home energy advice tools, compared to EPCs

Table 6: Summary of customisable inputs of existing interactive home energy advice tools, compared with GDOA

Table 7: Qualitative assessment matrix for data inputs

1. : Methodology

Review of existing EPCs to identify data inputs and outputs for potential interactivity

An example of the current Scottish EPC format was reviewed. Outputs relevant to end users making decisions for energy efficiency and clean heat measures were identified. The Scottish Government consultation on EPC reform was also reviewed to give insight on future changes/ additional outputs.

The SAP calculation methodology used to create EPCs (RdSAP 2012 v9.94) was interrogated to extract the input data that could be customised to create the identified outputs. This focussed on metrics for which standardised assumptions are used by default in the calculation (e.g. occupancy). The Green Deal Occupancy Assessment, as set out in Appendix V of RdSAP 2012 v9.92, was referenced to help identify contextual parameters. The ease of implementation to make each output interactive was assessed qualitatively with developers in BRE’s SAP team. This followed a ‘high, medium, low’ rating based on the following criteria:

• High ease: Where an output already held on the Scottish EPC register could be adapted via a straightforward calculation (i.e. no SAP calculation engine required).
• Medium ease: Where the output could be updated by implementing aspects of the GDOA as part of a new RdSAP calculation, using data held on the EPC register.
• Low ease: Where customisation of metrics has not previously been implemented in an RdSAP calculation, hence more work would be required to implement.

The likely importance/ value of each output, from an end user perspective, was qualitatively assessed, again on a ‘high, medium, low’ scale. This synthesised information from several sources:

• Information from literature sources (identified in subsequent tasks)
• Expertise of BRE staff that work in the retrofit sector
• Discussions with customer-facing practitioners from NEF

Review of existing consumer energy advice tools

Existing consumer-facing energy advice tools were identified using web searches and the knowledge of the research team. CXC had additionally cited the UK Government household energy tool and EST Renewables selector for consideration. Criteria for identifying tools included:

• A domestic/ housing focus
• An aspect of interactivity/ customisation
• Outputs similar in nature to those shown on EPCs (i.e. energy use, cost, recommendations)

A representative selection of tools were shortlisted for more detailed investigation. Criteria for shortlisting included:

• Limited duplication of tools created by a single organisation, unless they offered something distinctly different from one another (e.g. there are many tools created with the same underpinning architecture/ calculation engine by EST)
• Tools offering different levels of interactivity/ customisation
• Inclusion of a commercial/ portfolio assessment tool (e.g. for social landlords)
• Sufficient information available on tools to allow them to be tested and explored as part of the research

Interviews were held with DESNZ and Core Logic as product owners of the ‘Find ways to save energy’ and ‘EcoRefurb’ shortlisted tools, respectively.

Relevant EU research projects (into enhanced or dynamic EPCs) were also explored. However, since the resulting tools were generally intended for use by professionals supporting households, they were not comparable to the other user-centric tools explored. They were therefore not reported alongside the other existing tools but instead informed the wider evidence review on intended outcomes.

Assessment of data collection/ sourcing methods

Methods of data collection/ input were identified using web searches. This used key words on data input sources (taken from the task described above) linked to concepts of ‘collection, data entry, data history, automation, smart’. Further methods were populated based on the research team’s own experiences and expertise in data entry and surveying for SAP/ EPCs. Novel approaches being explored by Innovate UK projects were publicised during the ‘Net Zero Heat Open Day’^[7]. These were also reviewed for relevance.

Approaches were assigned as ‘manual’ versus ‘automated’ methods. It was also flagged if the data was already held on the EPC register or elsewhere linked to the creation of EPCs (e.g. the PCDB). The potential data sources/ collection methods were qualitatively appraised, based on the research team’s judgement, on a ‘high, medium, low’ scale against the following parameters:

• The ease of data input for the user
• Likely reliability of the information
• Likelihood of an information source to be available short-mid term

Table 8 gives a practical illustration of the criteria for assigning the qualitative rating. The rankings were then assigned a score (High = 3, Medium = 2, Low = 1). These were summed to provide an overall current ‘readiness’ metric for each approach (scored out of 9).

Table 8: Example criteria for assigning ‘high, medium, low’ qualitative ratings to
data collection/ sourcing methods.

Identifying evidence of intended outcomes

A desk-based evidence review sought information from academic articles and grey literature. A selection of search terms used are given in Table 9. These were expanded upon as other terms and concepts were identified in the reviewed sources. Feedback linked to the example energy advice tools identified in an earlier task was also sought. This was from online sources, though additional discussions were also held with tool developers where possible. DESNZ (as owners of the UK Government ‘Find ways to save energy’ tool) and Core Logic (EcoRefurb tool) provided direct feedback on their respective tools. Additionally, advisors from NEF provided general feedback from their experiences of directly supporting consumers with retrofit projects and from administering grants.

Research was widened to ‘relatable activities’ based on the research team’s experiences in the energy and retrofit sector. The scope for this was limited to households and housing, and at least energy-related behaviours, if not retrofit. This included researching linkages between interactive outputs and intended behavioural change on smart meters, retrofit plans and green finance (for retrofit).

Table 9: Initial search terms used for evidence review (not exhaustive)

How to cite this publication:

Weeks, C. and Sinclair, C. (2025) ‘Potential for interactive EPCs for Scotland’, ClimateXChange. DOI: http://dx.doi.org/10.7488/era/6008

© The University of Edinburgh, 2025
Prepared by BRE 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

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

1. 
   

   As set out in the SAP Technical Appendix document RdSAP 2012 v9.94 (BRE, 2019) ↑

   
   
2. 
   

   RdSAP 2012 version 9.92: Occupancy Assessment version Mar 2014. (BRE, 2014) This supported the Green Deal funding initiative (2012-2015) to ensure the cost of retrofit repayments would not exceed energy bill savings. ↑

   
   
3. 
   

   The GDOA tool underpins the UK Government Find Ways to Save Energy tool discussed in section 5.2.1. ↑

   
   
4. 
   

   Note that others including EST, Core Logic and BRE also provide tools for this market. ↑

   
   
5. 
   

   Note that much innovation and research is underway into obtaining ‘real’ data for fabric performance metrics for use in SAP. For example, there are projects funded by Innovate UK exploring monitoring solutions, U-value measurement and automated thermography for fabric elements. However, inputs relating to building fabric performance and dimensioning were beyond the scope for this study. ↑

   
   
6. 
   

   Virtually all outputs were identified as having the same ease of customisation in section 5.1.3. Therefore, outputs with highest perceived importance to consumers have instead been selected as the focus here. ↑

   
   
7. 
   

   UKRI Innovate UK Net Zero Heat Open Day – Innovate UK Business Connect. Held online 03/10/24. Recordings available. ↑

   
   

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

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+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. ↑

    
    

Research completed October 2024

DOI: http://dx.doi.org/10.7488/era/5798

Executive summary

Aims

Scotland has abundant renewable energy resources that could supply significantly more energy than it consumes. This presents a substantial opportunity for Scotland to become a net exporter of low-carbon energy, boosting employment, supporting economic growth and helping to deliver international decarbonisation.

In our research, we review, assess, and rank the potential of technologies that could enable cost-efficient domestic and international trade of hydrogen, as well its derivatives and products. Hydrogen derivatives are substances that contain hydrogen, manufactured for the purposes of transporting energy and converted back to hydrogen before use (e.g. ammonia). Hydrogen products are anticipated to be used directly, with no need for reconversion (e.g. sustainable aviation fuel). Further, we identify offtake sectors and countries, assess the scale of demand in potential markets, and identify gaps and opportunities in domestic and international policy.

We carried out desk-based research and targeted stakeholder interviews to gather data and review a range of hydrogen derivatives and products.

Findings

Hydrogen and derivative offtake markets

• Scotland’s hydrogen potential poses an unprecedented opportunity to strengthen domestic industrial capabilities and cut greenhouse gas emissions. Hydrogen production capacity is anticipated to exceed Scottish demand in the future.
• Industrial clusters in Scotland, England and Wales all provide a large local market for hydrogen and its derivatives and products. Existing industrial demand, proximity, and a similar regulatory framework offer key advantages over mainland Europe.
• The European Union and its member states are unlikely to meet their low-carbon hydrogen demand on their own, creating an export opportunity for Scotland. Germany and the Netherlands are likely to become the dominant hydrogen offtakers in Europe. But because international trade requires extensive infrastructure and harmonised low-carbon certification frameworks, we identify domestic hydrogen offtake markets as having greater potential.

Hydrogen derivatives

• Subsea hydrogen pipelines are critical to enhancing the competitiveness of Scottish hydrogen for trade within Europe. Alternative delivery methods and hydrogen derivatives have substantially higher costs.
• Ammonia is expected to be the dominant hydrogen derivative in the medium to long term for global trade. This is due to high technical maturity, relatively high roundtrip efficiency, low production and transport costs, and established global market.

Hydrogen products and end use cases

• Industry – including oil and biofuel refining, ammonia, and synthetic fuel production – will be the biggest driver of hydrogen demand in 2030 in both the EU and the UK. By 2045, other sectors like aviation, shipping, power generation are also expected to be major players in the hydrogen economy.
• Some end-use sectors, such as chemicals and aviation, will be able to use hydrogen derivatives and products directly, avoiding substantial costs on reconversion. Emerging policies in the UK and in the EU make the market highly attractive to potential hydrogen exporters.
• Synthetic methanol will be key to decarbonising existing industrial uses of methanol and in initial low-carbon maritime projects. However, uncertainty around maritime policy and the future availability and cost of biogenic CO₂ remains.
• In the long term, hydrogen is also expected to play a significant role in power generation, where it could replace natural gas and other fossil fuels in peaking plants.
• Hydrogen-based Sustainable Aviation Fuels (SAF) are well-placed to decarbonise the aviation sector due to compatibility with existing infrastructure, policy support in the UK and Europe, and no commercially viable low-carbon alternatives.
• The main low-carbon alternatives to hydrogen include Carbon Capture, Utilisation, and Storage (CCUS) and bio-based technologies.

Recommendations

1. Stimulate demand by improving alignment – Align the UK and EU Emissions Trading Systems to avoid potential carbon taxes on UK products including maritime fuels. The timely launch of the UK Carbon Border Adjustment Mechanism (CBAM) is also critical.
2. Stimulate demand by supporting trials and demonstration projects – Subsidy schemes, such as the Hydrogen Innovation Scheme, trials and demonstration projects help to create learnings, improve investor certainty and get initial projects off the ground.
3. Support infrastructure – Support key new-built and repurposed infrastructure projects including a core UK hydrogen network, ports, terminals, hydrogen boilers, refuelling stations and salt cavern storage.
4. Enhance competitiveness of Scottish hydrogen – To effectively compete with renewable rich regions, Scotland needs to meet a lower levelised cost of hydrogen. High electricity prices are one of the biggest weaknesses in Scotland’s hydrogen ambitions.
5. Reform the planning and permitting regime – Streamline complex processes where possible to avoid unneeded congestion and accelerate decarbonisation. Work with the Health and Safety Executive (HSE) to develop the safety case for hydrogen.
6. Optimise low-carbon policy frameworks – The Hydrogen Production Business Model needs to be optimised to interact with other low-carbon policy frameworks, such as the Contracts for Difference Scheme, Hydrogen T&S Business Models and the H2P Business Model.
7. Co-ordinate with the EU – Infrastructure projects have long associated lead times and limited flexibility once approved. Therefore, coordinating infrastructure deployment with the European Hydrogen Backbone and port infrastructure is essential.
8. Continue progress on low-carbon certification – A mutually recognised low-carbon hydrogen standard is critical to the success of hydrogen trade.
9. Engage local communities – Continue to engage with local communities and improve public understanding of hydrogen’s role in a net zero energy system.
10. Set out strategy on hydrogen trade – The Scottish Government could work with the UK Government on a clear strategy for how to develop hydrogen export capacity.

Glossary and abbreviations

Glossary

Abbreviations

Introduction

Context

Scotland has abundant renewable energy resources which could supply significantly more energy than is consumed nationally. This presents an opportunity for Scotland to become a net exporter of low-carbon energy, potentially boosting employment and economic growth, and helping to deliver international decarbonisation.

In addition to electricity interconnectors, low-carbon energy is expected to be exported via mediums including low-carbon gases such as hydrogen. Scotland has ambitions to produce 5 GW of low-carbon hydrogen by 2030, rising to 25 GW by 2045 [1]. As emphasised by the Scottish Hydrogen Assessment, Scotland has the potential to grow a strong hydrogen economy [2]. The Scottish Government signalled its ambition for Scotland to ‘become a leading producer and exporter of hydrogen and hydrogen derivatives for use in the UK and in Europe’ [3]. Projections estimate that 75% of this production (by volume) could be exported to UK and European markets [3] [4]. This rise in production is expected to coincide with hydrogen demand growth in the rest of the UK and the European Union (EU), with the EU targeting 20 Mt of hydrogen per annum by 2030, half of which is expected to come from imports [5]. European industrial clusters are likely to be major offtakers and importers of hydrogen and derivatives due to high industrial demand, ambitious decarbonisation targets and limited renewable resources.

The movement of hydrogen over longer distances is not yet well proven. While existing research has confirmed the cost efficiency of future hydrogen pipelines linking the UK and mainland Europe [6], subsea hydrogen pipeline interconnectors are capital cost-intensive and have long lead times [7], making the Scottish Government’s ambition to export hydrogen in the 2020s [3] challenging without alternative options. Due to the low volumetric density of gaseous hydrogen, hydrogen-carrying derivatives are likely to be used in the absence of a centralised hydrogen pipeline network.

Hydrogen derivatives are substances that are manufactured using hydrogen and are generally capable of transporting hydrogen with higher volumetric energy density. Hydrogen products are also made with hydrogen, but are anticipated to be used directly, with no need for reconversion.

A range of technologies are available to increase the volumetric energy density of hydrogen for easier long-distance transport and storage. At a low temperature, gaseous hydrogen can be turned into liquid hydrogen. Liquefaction can help with storing hydrogen in smaller spaces for longer periods of time, transporting it and using it as aviation or shipping fuel. Hydrogen can also be reacted with nitrogen at high temperature and pressure to produce ammonia. Liquid ammonia can be stored more readily than liquified hydrogen due to it having a higher volumetric energy density. When transported to its destination, ammonia can be cracked back into hydrogen and nitrogen or used directly as ammonia in industrial applications. Liquid Organic Hydrogen Carriers (LOHCs) absorb hydrogen in an organic compound. This work focuses on the most advanced organic carrier, methylcyclohexane, which can be easily broken down to hydrogen and toluene. Lastly, metal hydrides, such as magnesium hydride, can carry hydrogen in a solid state, making international trade safer and simpler.

Methodology

We carried out desk-based research and targeted stakeholder interviews simultaneously to gather data and review a range of hydrogen derivatives and products. This dual approach was key to ensuring the interdisciplinarity of the research and bringing together technical, economic and policy aspects. More details can be found in the appendices (section 10).

To assess hydrogen derivatives and products and produce a clear, non-technical output, we assigned Red-Amber-Green (RAG) ratings to each hydrogen derivative and product. Clarification of these RAG categories is provided in Table 1.

Table 1: Red-Amber-Green rating classification

Hydrogen Product and end use case mapping

Hydrogen is already used in a wide range of sectors, with 2022 consumption in the UK reaching more than 568,000 tonnes (22.3 TWh_HHV) [8]. Most existing hydrogen demand is taken up by oil refining. While hydrogen today is mainly used for oil desulphurisation, its use in biorefineries for hydrogenation is anticipated to grow in the future as demand for biofuels increases [9]. Hydrogen is critical for ammonia and fertiliser manufacturing, making it the second largest end use case in the UK in 2022 [8]. It is also used as a feedstock in the chemical sector, most importantly, for methanol production. While the methanol industry is limited in the UK, low-carbon methanol production is an area of emerging interest domestically. Furthermore, demonstration projects are underway to investigate the use of hydrogen in steel manufacturing. Hydrogen is not currently used in steel making, but directly reduced iron may become the dominant technology by 2050 (see section4.2).

In addition to existing end use cases in industry, we also reviewed end use cases in three sectors: high-temperature heat, transport, and power generation (see Table 2). UK research suggests that hydrogen can be used in most industrial equipment for heat generation, reducing capital costs (CAPEX) in the manufacturing sector as compared to installing new industrial equipment [10]. Low-carbon alternatives include carbon capture and storage (CCS) and biomass technologies. Hydrogen and its derivatives are also well placed to decarbonise some hard-to-electrify transport applications. While hydrogen can be used directly in fuel cell vehicles, the low volumetric density of gaseous hydrogen or high storage costs associated with liquified hydrogen could require it to be converted into derivatives such as methanol, ammonia or other synthetic fuels. This is particularly the case for long-distance and heavy transport. Lastly, our literature review and stakeholder engagement suggested that hydrogen technologies have a high potential to decarbonise dispatchable power production. Existing power plants can be run on hydrogen, ammonia, biomass or retrofitted with CCS technologies. Technologies shown in Table 2 are assessed in section 4.2.

Table 2: Hydrogen products and end use case mapping from our research

Hydrogen Derivative and Product Assessment

Hydrogen, derivatives and low-carbon alternatives

A range of hydrogen and alternative low-carbon technologies are available to export surplus renewable energy from Scotland to domestic and international demand centres. Table 3 summarises RAG ratings for hydrogen, derivatives and interconnectors. Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

		H2	H2	NH3	C21H20	MgH2
	High voltage inter-connectors	Gaseous H2 pipelines	Liquid hydrogen	Ammonia	LOHC	Metal hydrides
Economic case (short distance[1])	AMBER	GREEN	GREEN	AMBER	AMBER	AMBER
Economic case (long distance[2])	RED	RED	RED	GREEN	AMBER	AMBER
Technical feasibility	GREEN	GREEN	GREEN	AMBER	AMBER	AMBER
Scottish capabilities	GREEN	AMBER	AMBER	RED	RED	RED
Sustainability	GREEN	GREEN	AMBER	AMBER	AMBER	GREEN

Table 3: RAG ratings for hydrogen, derivatives and interconnectors

High voltage direct current (HVDC) interconnectors already connect the UK with neighbouring countries, allowing the energy system to manage electricity peaks and enhance energy security. To increase export capacities and achieve higher system benefits, HVDC interconnectors can be complemented with hydrogen production, using excess renewable energy and exporting it to UK and European demand centres.

Hydrogen pipelines are the most mature and cost-efficient way to transport hydrogen over short and medium distances. However, due to long lead times and high capital costs they are not expected to be available at larger scale in the short term. Like other gases, hydrogen can be shipped in liquid form, which requires an extremely low temperature of −253°C. Hydrogen derivatives are simpler to transport due to their higher energy density and higher transport and storage temperature.

The most widely used hydrogen derivative is ammonia (NH₃), which is produced by reacting hydrogen with nitrogen at high temperatures and pressures. Ammonia has an established global market and is simpler to handle than liquid hydrogen as the boiling point of liquified ammonia is more than 219°C higher than that of liquefied hydrogen.

Organic compounds can also absorb hydrogen into their structure, forming LOHCs. These compounds remain stable as a liquid during transport even at ambient temperature and pressure, making them highly compatible with existing oil assets.

Although metal hydride technologies are relatively new, their simplicity and safety case could make them competitive with other hydrogen technologies. We took magnesium hydride as a case study as it can be easily shipped in a solvent slurry. Methanol is unlikely to be reconverted back to hydrogen at the point of destination. This is due to the economic case and carbon emissions associated with the methanol steam reforming reconversion process.

Hydrogen products

In some cases, hydrogen and its products can be used directly without the need to reconvert derivatives back to hydrogen or low-carbon power. This direct use can significantly improve overall round-trip efficiency, making the trade of hydrogen products an area of emerging interest. The availability of low-carbon alternatives is introduced as an additional factor in the analysis. A green rating is assigned to end-use cases with no or limited availability of alternatives, supporting the case for hydrogen use. A red RAG rating indicates widespread availability of low-carbon alternatives.

Industrial feedstock 

The four main non-energy applications of hydrogen in industrial feedstock are ammonia for fertiliser, methanol production, oil refining and green steel production [11]. Table 4 summarises RAG ratings for selected end-use cases for hydrogen products. Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

	NH3	CH3OH
	Ammonia	Methanol	Refining	Green steel
Economic case	N/A	AMBER	N/A	GREEN/AMBER*
Technical feasibility	GREEN	GREEN	GREEN	AMBER
Scottish capabilities	RED	RED	GREEN	AMBER
Sustainability	AMBER	GREEN	GREEN	GREEN
Low-carbon alternative	GREEN	GREEN	GREEN	AMBER

Table 4: RAG ratings of selected end use cases for hydrogen products

(* – depending on whether hydrogen is used as a reducing agent or in blast furnaces)

Hydrogen is critical for oil refining and the production of ammonia, a key chemical used for fertiliser, plastic or synthetic fibre fabrication. In oil refining, hydrogen is primarily used in hydrocracking and hydrotreating processes. Hydrocracking uses hydrogen and a catalyst to break down heavy hydrocarbons into lighter fractions like jet fuel, petrol and diesel. Hydrotreating removes impurities from hydrocarbon streams with desulphurisation being a key process to improve petrochemical quality and reduce sulphur oxide emissions at the point of use, thereby preventing acid rain.

While its role in fossil fuel refining may decline, low-carbon hydrogen will remain crucial in biorefineries for producing synthetic and biofuels like hydro-processed esters and fatty acids (HEFA), hydrotreated vegetable oils (HVO) and biodiesel.

Hydrogen is essential for both conventional and synthetic methanol production. Although methanol can be produced using bioresources [12], bio-based methanol alone is unlikely to meet global demand [13]. This makes synthetic methanol crucial for timely and large-scale industrial decarbonisation. Syngas, a mixture of hydrogen, CO and CO₂ molecule can be produced through natural gas reforming or by combining low-carbon hydrogen with sustainably sourced CO₂. This mixture undergoes methanol synthesis, a process where it reacts at high pressure and moderate temperatures to produce methanol (CH₃OH).

In contrast to the end use cases mentioned above, producing green steel requires new steel making equipment. Hydrogen, as an effective reducing agent for iron ore, holds significant potential to decarbonise steel and iron production. While some low-carbon alternatives exist, the IEA anticipates hydrogen-based direct reduced iron (DRI) technology coupled with electric arc furnace will dominate, contributing 44% of all emission reductions in the iron sector [14].

High temperature heat 

High temperature heat is essential for various industrial processes including cement, ceramic and glass manufacturing. However, decarbonising high-temperature industrial heat is among the most challenging tasks due to technical difficulties and cost inefficiencies associated with generating such heat (>1000 °C) using existing electric technologies [15].

The need for low-carbon technologies is becoming more urgent as approximately 4,300 industrial heating units in the UK rely on gas, representing 70% of the country’s industrial gas consumption [10]. Existing equipment can be retrofitted to use hydrogen, generating direct and indirect heat up to 1000 °C.

Low-carbon alternatives including biofuels such as biomass or biomethane, and CCUS technologies are also viable. With CCUS, industrial plants are upgraded with post-combustion carbon capture systems, which store the resulting greenhouse gases in underground reservoirs.

Table 5 summarises RAG ratings for high temperature heat use. Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

	H2
	Hydrogen	CCUS-enabled gas	Bio-based products
Economic case	AMBER	AMBER	GREEN
Technical feasibility	GREEN	AMBER	GREEN
Scottish capabilities	AMBER	AMBER	GREEN
Sustainability	GREEN	AMBER	GREEN
Low-carbon alternative	AMBER	N/A	N/A

Table 5: The RAG ratings of selected high temperature heat use

Transport

Hydrogen can be used in fuel cell vehicles and has been shown to be able to be cost competitive with other fuels with government subsidies [16]. While the economic case for fuel cell heavy good vehicles (HGVs) is fairly well established [17], there is more uncertainty around lighter vehicles [18]. Battery-electric passenger vehicles and light duty vehicles (LDV) are likely to be more cost competitive compared to their fuel cell equivalents.

Sustainable Aviation Fuel (SAF) is currently used in aviation to reduce carbon emissions, and the similar composition as current options allows for storage for long periods of time in the same infrastructure [19]. While the industry continues to explore alternatives to SAF, there is a wide consensus that aviation is a hard-to-electrify sector. Both the EU and the UK have mandated the use of SAF from 2025 (see Figure 1). SAF is anticipated to be the dominant decarbonisation pathway, with other low-carbon fuels such as hydrogen taking up very small shares of the market [20].

Synthetic methanol and ammonia will increasingly be used as fuels in the maritime industry, as there are not many other alternatives. In case of shorter distances, some ships and ferries may be powered electrically with batteries or fuel cells [21]. A Norwegian ferry currently powered by hydrogen fuel cells can reduce yearly emissions by 95% [22].

Table 6 summarises RAG ratings for transport uses. Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

			CH3OH	NH3
	Hydrogen (fuel cell)	SAF	Methanol (maritime)	Ammonia (maritime)
Economic case	AMBER	AMBER	AMBER	GREEN
Technical feasibility	GREEN	AMBER	GREEN	RED
Scottish capabilities	AMBER	AMBER	RED	RED
Sustainability	GREEN	GREEN	AMBER	AMBER
Low-carbon alternative	RED	GREEN	AMBER	AMBER

Table 6: The RAG ratings of selected transport uses

Power generation

Renewables are well placed to decarbonise a large share of the electricity supply. However, due to intermittency challenges, electricity generation cannot always meet electricity demand. Hydrogen, ammonia and biomass are all low-carbon fuels that can be used in turbines to meet electricity demand when required. Alternatively, CCUS enabled gas turbines are an alternative that do not require major alterations of existing fossil fuel infrastructure, with the CO₂ captured stored underground.

While all technologies reviewed in this section can generate power, they are not necessarily perfect substitutes (see Figure 1). Our stakeholder engagement confirmed that the main role of hydrogen is expected to be in peaking generation, with bioenergy with carbon capture and storage (BECCS) running at baseload due to high capital costs and substantial carbon benefits [23].

Power generation in Great Britain is dispatched in the order of merit or cost. Baseload units, for example nuclear power plants, run throughout the year. Mid-merit units, for example combined-cycle gas plants operate up to thousands of hours per year. Power plants that operate no more than 5% of the year are generally referred to as ‘peaking plants’ [24].

Table 7 shows the RAG ratings of selected power generation methods, with the ‘low-carbon alternative’ factor not being applicable to non-hydrogen technologies, such as gas CCUS, biomass and ammonia.Further discussion on the economic case, technical feasibility and sustainability can be found in Appendix A.

	H2			NH3
	Hydrogen	CCUS-enabled gas	Biomass	Ammonia
Economic case	GREEN	GREEN	GREEN	AMBER
Technical feasibility	AMBER	AMBER	GREEN	RED
Scottish capabilities	AMBER	GREEN	GREEN	RED
Sustainability	GREEN	AMBER	GREEN	AMBER
Low-carbon alternative	AMBER	N/A	N/A	AMBER

Table 7: The RAG ratings of selected power generation methods

E-METHANOL IN MARITIME

FEWER ALTERNATIVES

MORE ALTERNATIVES

LOW TECHNOLOGY READINESS

HIGH TECHNOLOGY READINESS

REFINING

CHEMICALS

HYDROGEN
INTERCONNECTORS

STEEL

HIGH-TEMPERATURE
HYDROGEN HEAT

AMMONIA
IN MARITIME

AMMONIA
POWER GENERATION

SMALL-SCALE
HYDROGEN
POWER AND CHP

HYDROGEN IN
LIGHT VEHICLES

HYDROGEN IN
HGVs

SUSTAINABLE

AVIATION FUEL

SMALL MARITIME
APPLICATIONS

LOW-TEMPERATURE
HYDROGEN HEAT

LARGE-SCALE HYDROGEN
POWER

Figure 1: Technical and alternative technology assessment of selected hydrogen products and end use cases

ENERGY CARRIER

POWER GENERATION

TRANSPORT

INDUSTRIAL HEAT

INDUSTRIAL FEEDSTOCK

Offtaker Market Assessment

We assessed potential offtake markets for hydrogen derivative and products, covering Scotland, the rest of the UK, the Netherlands, Belgium, Germany and the European Union as a whole. Our findings are summarised in Table 8.

	SCOTLAND	REST OF THE UK	GERMANY	NETHERLANDS	BELGIUM	WIDER EU
DISTANCE	GREEN	GREEN	AMBER	AMBER	AMBER	AMBER
INFRASTRUCTURE	GREEN	GREEN	AMBER	GREEN	AMBER	GREEN
EXISTING DEMAND	AMBER	AMBER	GREEN	GREEN	AMBER	GREEN
PROJECTED DEMAND	AMBER	GREEN	GREEN	GREEN	AMBER	GREEN
POLICY LANDSCAPE	GREEN	GREEN	GREEN	GREEN	AMBER	GREEN

Table 8: The RAG ratings of selected offtaker markets

Distance from Scotland and rest of UK 

Our stakeholder engagement confirmed that distance is a key factor determining the price of both domestic and international hydrogen transport. The cost associated with all methods of hydrogen transportation increases linearly with the distance. Shorter distances between hydrogen production sites and demand centres result in lower capital costs for pipelines or tube trailers, compared to long-distance shipping. This means that the lowest associated costs are found within Scotland. Multiple stakeholders highlighted the potential benefits of co-locating hydrogen production and end-user project, substantially reducing the cost of hydrogen transport.

The nearest potential demand hotspots to Scotland are in the rest of the UK, with the closest being the industrial clusters in the North of England and Wales. Internationally, the closest industrial offtake markets are in the Netherlands, Belgium and Germany, in order of proximity. While distance to the nearest hydrogen terminal is highly relevant in the short term, its importance is expected to decrease as the intra-European hydrogen infrastructure, the European Hydrogen Backbone, becomes available. Once a centralised hydrogen market is in place, Central or Eastern European markets are anticipated to be accessible from Western Europe.

Infrastructure gap and opportunity

Hydrogen trade infrastructure, including ports, terminals, onshore and offshore pipelines, is key to removing barriers to trade. In contrast to the UK’s limited hydrogen infrastructure, Europe has around 2,000 km of hydrogen pipelines [25], with further extensions needed to avoid market inefficiencies. Existing infrastructure, for example gas interconnectors, can be leveraged and repurposed to bring down CAPEX costs. Subsea natural gas interconnectors already link Great Britain with Northern Ireland, Ireland, Norway, the Netherlands and Belgium. While IEA analysis suggests that the cost of hydrogen transport can be significantly reduced using repurposed pipelines [26], our stakeholder engagement suggests that the majority of the natural gas assets are unlikely to be altered, to maintain energy security.

While some of the fossil fuel infrastructure is required to stay in place, it is critical to develop purpose-built hydrogen assets, especially given the long lead times associated with new developments. To supplement and link up regional pipelines, the European Hydrogen Backbone project aims to develop 53,000 km of hydrogen pipelines by 2040. The REPowerEU Plan set out three major import corridors via the Mediterranean, the North Sea area and Ukraine. Germany and the UK signed a Memorandum of Understanding in 2023 strengthening collaboration on energy and climate, including security of energy infrastructure [27]. Research conducted by the Net Zero Technology Centre is ongoing to explore the feasibility of a subsea hydrogen pipeline between Scotland and mainland Europe [28]. Stakeholders suggested that further coordination with the European Union is key to ensure alignment between infrastructure.

All selected European countries have strategy on domestic pipeline infrastructure roll-out. Germany has a well-established network of pipelines especially in the north-west and is aiming to add 4,500 km of hydrogen pipeline using Important Projects of Common European Interest (IPCEI) funding [29]. The Netherlands is also aiming to link industrial clusters with a national hydrogen network by 2030 [30].

European ports and terminals, critical for long-distance import and export, are developing similar strategies. The Port of Rotterdam aims to supply 4.6 million tonnes of hydrogen per year by 2030 (181.2 TWh_HHV) [31], with projections suggesting a capacity of 20 million tonnes per year by 2050 (788 TWh_HHV ) [32] become major renewable energy hubs. More detail on infrastructure projects can be found in Table 11 (Appendix B).

As well as infrastructure to support the supply and trade of hydrogen, there is also a need for demand-side infrastructure to complete the value chain with offtake. This includes hydrogen refuelling stations, hydrogen boilers, salt caverns for storage and hydrogen-powered furnaces etc. For example, the EU’s Alternative Fuels Infrastructure Regulation includes a required number of hydrogens refuelling stations along it’s TEN-T core network, a road network that includes the most important connections between major cities and nodes, planned for completion by 2030. The regulation states that a hydrogen fuelling station with a cumulative daily capacity of one tonne, dispensed at least a 700bar, is required every 200km to “ensure a sufficiently dense network to allow hydrogen vehicles to travel across the EU.”

Meanwhile, many European countries are targeting a phase out of fossil-fuel powered household boilers by 2035, with clean hydrogen boilers seen as a key alternative. Development of demand infrastructure currently requires support from similar policies across the value chain, with several EU policy schemes such as the Emission Trading Scheme, SAF Mandates and Road Transport Fuel Obligation (RTFO). With the policy and investment progressing, demand-side infrastructure will follow. This presents an opportunity for Scotland to partner with the EU to shape and support these supply chains as they develop and provide the necessary hydrogen supply.

Existing demand for hydrogen and hydrogen products 

While existing demand is mainly met by fossil fuel derived hydrogen and derivatives, the share of low-carbon hydrogen is expected to increase given emerging mandates, policy frameworks and increasing carbon prices. The Netherlands and Germany were the leading hydrogen trading countries in 2023, with a total import of 194,096,000 m³ and 6,322,280 m³ of overwhelmingly fossil-based hydrogen, respectively [33] (see Figure 15 in Appendix B).

Figure 2, below, shows the consumption of hydrogen in the UK, Belgium, Germany, the Netherlands and the whole of EU for the year 2022. In the EU, Germany is the largest consumer of hydrogen followed by the Netherlands, whereas Belgium is the 9^th largest consumer. Together, these three countries account for roughly 41% of the total consumption of hydrogen in EU [8].

Figure 2: Total hydrogen consumption in the EU, the Netherlands, Belgium, the UK and Germany in 2022

Projected demand for hydrogen derivatives and products 

As countries progress toward net zero targets, demand for hydrogen and hydrogen derivatives and products is expected to rise. On a European scale, the UK and Germany have the most ambitious short-term demand for hydrogen. The UK Government has estimated between 80 and 140 TWh in demand by the end of 2035 [34] [35]. For Scotland, as shown in section 7.3, analysis by Gemserv projects hydrogen demand to range from 0.6 TWh to 2.8 TWh by 2030, and from 2.9 to25 TWh by 2045.

Germany set a target of 95 – 130 TWh by 2030 [29] with independent projections in line with this range (42 – 72 TWh of demand by 2030) [4]. By 2045, forecasts range from 184 to 694 TWh depending on assumptions. Belgium anticipates a demand of 20 TWh by 2030 but expects a sharp increase to 200-230 TWh by 2050 [36]. The Netherlands has projected demands of 120 TWh (2050) [37]. Demand scenarios developed as part of this research are discussed in Appendix E.

Policy landscape and net zero ambitions 

Scotland has an ambitious net zero target for 2045. This is five years ahead of the UK’s net zero target. Both Governments have published strategies and action plans on hydrogen production. However, stakeholders highlighted the lack of clarity on regional and hydrogen trade strategy. This perceived lack of clarity and of commitment to specific targets and routes could be a competitive disadvantage compared to other European countries.

In the UK, hydrogen production projects will be subsidised under the Hydrogen Production Business Model (HPBM). The HPBM will ensure it only stimulates production of hydrogen that is low-carbon by requiring volumes to comply with the Low Carbon Hydrogen Standard (LCHS) which sets a maximum emissions limit of 20 gCO_2e/MJ [38]. While hydrogen production using imported natural gas is eligible for support under the Cluster Sequencing programme, the HPBM is not expected to support any form of hydrogen or hydrogen derivative import [38] and export [39].

In the absence of UK-wide policies supporting hydrogen trade, its main driver is expected to be international hydrogen import subsidies, mandates and targets. While the UK has committed to designing generous hydrogen business models, our stakeholder engagement suggests that regulatory bottlenecks remain, particularly around electricity market and the planning and permitting frameworks. According to stakeholders, the Review of Electricity Market Arrangements (REMA) is critical to cut the currently ‘very high’ grid electricity prices in the UK, particularly in Scotland. With hydrogen costs highly sensitive to electricity prices, reducing these will be essential to improving Scottish hydrogen competitiveness.

Stakeholders also reported that hydrogen regulation is fragmented and dated, with the planning and permitting process being more complex and lengthier compared to ‘other industrial countries’. These findings are in line with a 2023 research paper commissioned by DESNZ [40]. Scotland and UK specific regulatory bottlenecks are detailed in Table 18 (Appendix D).

The EU aims to be carbon neutral by 2050 [41]. It adopted a strategy on hydrogen in 2020 which focussed on 5 key areas: investment aid, production and demand, creating a hydrogen market (including infrastructure), research and international co-operation [42]. In the 2022 REPowerEU Plan, the European Commission set an ambitious 20 million tonne (equivalent to approximately 330 TWh) hydrogen target for 2030, with the EU aiming to import half of this [43]. Ambitious European import targets could offer potential opportunities to Scottish hydrogen exporters.

The German Federal Government established H2Global in 2021, a double auction model designed to facilitate inter-continental hydrogen trade [44]. In 2023, the European Commission decided to link the European Hydrogen Bank with H2Global to allow all EU member states access to the funding mechanism and agreed to jointly develop a European auction for international hydrogen imports [45]. Germany laid out an ambitious net zero target for 2045 [46] and their national hydrogen strategy states both a domestic hydrogen production target of 10GW alongside an import target of 90 TWh, potentially above 90% of the total demand forecast for 2030 [29]. They anticipate 2030 hydrogen demand to reach 95-130 TWh, around 50-70% (45 to 90 TWh) of which is forecasted be imported [29]. According to the National Hydrogen Strategy, pre-2030 imports are anticipated to be delivered by ships, with imports gradually expanding to pipeline-based solutions after 2030 [47].

Both the Netherlands and Belgium have net zero targets for 2050 and published national hydrogen strategies [48] [49]. The Netherlands has announced hydrogen import targets for 2030 for the Port of Rotterdam, 4.6Mtpa in 2030 increasing to 18Mtpa by 2050, and the Port of Amsterdam, 1Mtpa by 2030 [50]. Belgium has also set an import target of 0.6Mtpa, meaning that 62% of the continent’s 10Mtpa target could be met by these three ports [50].

The EU, along with member states are working towards a harmonised certification framework for low-carbon hydrogen to remove trade barriers [29] [51] [52]. Our stakeholder engagement suggests that misalignment between certification frameworks is expected to be the main bottleneck for international trade. UK and international hydrogen-related policies are further detailed in Table 19 (Appendix D).

SWOT Analysis

To shortlist high-potential hydrogen derivatives, products and end use cases, we considered the strengths, weaknesses, opportunities and threats associated with hydrogen derivatives and the trade of these products from a Scottish perspective.

Strengths

Strengths focus on the competitive advantages of Scotland.

As highlighted by a number of stakeholders, Scotland’s main competitive advantage in the hydrogen sector is access to abundant renewable generation capacity. As future renewable capacity is likely to exceed future electricity demand, Scotland is well placed to transition into an international hydrogen hub. Existing jobs, skills, and infrastructure, especially in the oil and gas and offshore wind sectors, could also confer a competitive advantage. Existing oil and gas infrastructure, such as gas interconnectors, ports, terminals and vessels, can be repurposed, resulting in savings in CAPEX. For example, due to the similarity of LPG and liquified ammonia, existing LPG terminals can be repurposed to import and export ammonia.

While Scotland does not have direct access to geological salt formations required for salt cavern hydrogen storage, depleted and partially depleted gas and oil reservoirs off the coast of Scotland could be suitable for large-scale hydrogen and CO₂ storage. Existing feasibility studies, demonstration projects, and trials funded by the Scottish and UK Governments are critical to get initial commercial projects off the ground.

Weaknesses

Weaknesses focus on the competitive disadvantages of Scotland.

Our research identified high grid electricity prices as the main competitive disadvantage of Scotland. Despite abundant renewables potential, high prices and network charges seem to prevent Scottish industry and consumers to capitalise on this advantage. Additionally, compared to other regions aiming to export surplus low-carbon hydrogen to European demand hotspots, Scotland’s relative disadvantage in solar generation could lead to greater intermittency, translating into higher hydrogen production costs.

In terms of infrastructure, electricity network constraints and limited energy storage capacity could prevent the energy system from mitigating temporal and geographic electricity imbalances. Lack of geological salt formations beneath Scotland will also amplify the challenge of storing large volumes of hydrogen in the absence of a UK-wide centralised hydrogen network.

Other weaknesses include limited experience in the production of ammonia, methanol, LOHC, and other derivative, as well as the lack of low-carbon hydrogen production on a commercial scale.

Opportunities

Opportunities focus on the future potential of Scotland as well as Scotland’s environment, offtake markets and competitors.

Hydrogen presents the opportunity to cut carbon emissions, reduce wind curtailment costs, boost economic growth and enhance energy security and resilience. In trade terms, stakeholders highlighted the opportunity for Scotland to strengthen existing industrial clusters and focus on high value-added industries instead of exporting low value-added fuels.

Although electricity prices are currently high, reforms under REMA could reduce costs for consumers. From an offtake market perspective, the main opportunity is to export hydrogen to industrial clusters in England and Wales. Once online, a core network connecting demand and supply hotspots can transport gaseous hydrogen in a cost-efficient manner. The North of England has the added benefit of large potential hydrogen storage capacities. By transporting hydrogen to Cheshire, Teesside or the Humber, Scottish producers could utilise large-scale storage facilities, enhancing flexibility and hedging against supply and demand-side shocks.

Regulatory misalignment—particularly around certification—is less of a barrier within the UK, as the Low Carbon Hydrogen Standard is expected to be applied nationally. Internationally, the increasing willingness of the EU, Germany and the Netherlands to import and subsidise low carbon hydrogen is a significant opportunity. Partially driven by the RED III directive, industry in the EU will have to meet a substantial share of their hydrogen demand from low-carbon by 2030.

Threats

Threats focus on the future risks in Scotland as well as risk associated with Scotland’s environment, offtake markets and competitors.

As our research identified hydrogen export to England as a high-potential opportunity, any delay in building out a core network connecting UK supply and demand hotpots is a threat to the growth of the hydrogen economy. In terms of international transport, lack of progress with hydrogen interconnectors, ports, terminals and vessels could further delay hydrogen derivative and product trade.

While Scotland is well-placed to supply hydrogen molecules through high-pressure pipelines, it may be outcompeted in the European market by lower cost, low-carbon hydrogen from renewable rich countries particularly in the form of ammonia, methanol and other hydrogen derivatives. This is because of high electricity prices, intermittency challenges and high hydrogen transport costs in the absence of subsea hydrogen interconnectors. However, the main threat on an international scale is the lack of a harmonised certification framework. As emphasised by the IEA, inconsistencies in low-carbon hydrogen standards risk becoming the main barrier for the development of international hydrogen and derivative trade [53].

Hydrogen Derivative and Product Demand

This section discusses the findings of the analysis, with the methodology used to develop these estimates shown in Appendix E. The analysis estimates the annual demand for hydrogen in the EU, the Netherlands, Germany, Belgium and England and Wales. Annual demand scenarios were developed for the years 2030 and 2045, and the demand was divided into various sectors and hydrogen products. The years 2030 and 2045 are selected due to their significance to policy targets for both the EU and Scotland. The RED III targets set out by the EU focus on accelerating the demand for hydrogen, among other fuels, by the year 2030 [54] and Scotland has a target of achieving net zero by the year 2045. Finally, in our analysis, hydrogen demand is modelled under three scenarios: High, Central, and Low in 2030 and 2045. The full demand mapping results can be seen in Appendix E.

Sectoral Demand

Figure 3 shows the modelled annual demand, by sector, for the whole of the EU for the years 2030 and 2045. Hydrogen demand is expected to be significantly higher in 2045, compared to 2030. The industrial demand^[3] shown in Figure 3 captures all industrial demand for hydrogen including demand for methanol and ammonia. The subsequent graphs in Figure 4 break down the industrial demand by product type.

Figure 3: Modelled annual demand for hydrogen and hydrogen derivatives in the EU

Figure 4 and Figure 5 show the expectation that demand for hydrogen use directly will be greater than demand for ammonia or methanol in both the 2030 and 2045 timeframe for the EU and nations considered. Demand for ammonia and methanol using low-carbon hydrogen will be driven by the RED III mandate which specifies that 42% of industrial hydrogen use (except refining) must utilise renewable fuels of non-biological origin (RFNBOs) by 2030. By 2045, it is expected that almost all ammonia and methanol will rely on low-carbon hydrogen.

Figure 4: Central Scenario EU Industrial Hydrogen Demand by Product in 2030 and 2045

Figure 5: Central Scenario National Industrial Hydrogen Demand by Product in 2030 and 2045

In all modelled scenarios for 2030 and 2045, the industrial sector is expected to remain the dominant driver of hydrogen demand in the EU. However, demand is likely to diversify between 2030 and 2045 largely because of increasing forecast contributions from the power generation sector – where hydrogen is expected to serve an important role in balancing the power system during times of low renewable generation.

For example, in 2030 the share of the industrial sector in the mix of total hydrogen demand ranges from 88% to 96% (Figure 6) but is expected to fall to within a range of 28% to 59% by 2045. Hydrogen demand in the transport sector is estimated to grow rapidly between 2030 and 2045 – largely driven by growth in demand for hydrogen as a low-carbon fuel for heavy transport, including maritime transport, aviation and HGV transport. In some scenarios, hydrogen consumption is further diversified between 2030 and 2045 by an increasingly large demand from the heating sector – which comprises as much as 14% of total hydrogen demand in the EU in the high scenario for 2045.

Figure 6: Share of different sectors and hydrogen derivatives of total hydrogen demand in the EU

Figure 7 and Figure 8 depict the modelled annual demand for hydrogen for Germany, Belgium, the Netherlands and England and Wales for different sectors in the years 2030 and 2045.

Figure 7 indicates that, consistent with the EU wide hydrogen demand, the industrial sector is anticipated to comprise most hydrogen demand in all countries by 2030. Similarly, reflecting EU-wide trends, hydrogen demand is expected to become increasingly diverse by 2045, when power generation, road transport and aviation will all likely also contribute to hydrogen demand in each of these markets. Hydrogen demand in the heating industry could also grow significantly in these markets; however, this is entirely dependent on the national policy landscape. For both 2030 and 2045, Germany and England and Wales are anticipated to drive most of the hydrogen demand.

Figure 7: Hydrogen demand for countries across all scenarios and sectors for the year 2030

Figure 8: Hydrogen demand for countries across all scenarios and sectors for the year 2045

Demand by Hydrogen Product

The total final demand for hydrogen, ammonia, methanol and sustainable aviation fuel (SAF) in the EU is shown in Figure 9. It is expected that hydrogen demand will be greater than any of the products assessed for both 2030 and 2045 making up 68% and 78% of demand, respectively. Of the products assessed, final demand for ammonia is likely to be greatest, estimated at 42 TWh in 2030. This is driven by low-carbon ammonia demand for use in fertilisers. It is expected that ammonia demand will rise to 206 TWh, with demand for maritime fuel making up over half of this total. Final demand for methanol derived from low-carbon hydrogen is expected to increase from 15 TWh to 20 TWh between 2030 and 2045. SAF demand from power to liquids in the EU is projected to increase from 4 TWh to 59 TWh between 2030 and 2045, due to the emerging SAF mandates.

Figure 9: Central EU Final Demand for Hydrogen and Products in 2030 and 2045

Figure 10 shows the central annual final demand for hydrogen and products by country. Similar to the EU as a whole, it is estimated that hydrogen has the highest demand for each region in both time periods. However, demand for ammonia could be significant, particularly in regions with significant maritime activity such as the Netherlands, where ammonia is estimated to form 44% of final demand in 2045. SAF demand is expected to be more evenly distributed across regions due to greater distribution of aviation activity. Methanol demand is relatively low across all regions ranging between 1 and 7 TWh per year by 2045.

Figure 10: Central National Final Demand for Hydrogen and Products in 2030 and 2045

Demand Scenarios for Scotland

As Figure 11 shows, the projected demand in Scotland is likely to be limited for the year 2030, ranging from just 0.6 TWh to 2.8 TWh from the Low to the High scenarios. The demand jumps up for the year 2045, ranging from 2.9 TWh in the Low scenario to 25 TWh in the High scenario^[4].

Figure 11 shows that for the year 2030, industry is the main driver for demand in Scotland. However, for the year 2045, other sectors like Road Transport and Power Generation play significant roles as drivers of demand.

These results reaffirm the export potential for Scotland as the hydrogen production capacity of Scotland is expected to be larger than the demand for hydrogen.

Figure 11: Annual demand for hydrogen and hydrogen derivatives for Scotland for 2030 and 2045

Figure 12 shows the range of demand for hydrogen and its derivatives for Scotland. The graph shows that the demand for all sectors, other than industry, is limited in all scenarios for the year 2030, with demand varying by sector significantly in 2045. For example, in the transport sector, the Low and High scenarios estimate a demand of 0.6 TWh and 7 TWh, respectively. This wide range is the result of high uncertainty of demand for hydrogen in the maritime and road transport sectors of Scotland for 2045.

Figure 12: Range for hydrogen & hydrogen derivatives across all sectors for Scotland

Comparison to Literature

A European Commission [55] (JRC) study reviewed a diverse range of literature and used the projections from different studies to determine average annual demand for hydrogen in the EU. According to the JRC study, the total projected annual demand for hydrogen in 2030 is 230 TWh [55], which lies towards the upper bound of this report’s estimate of 108-236 TWh. Similarly, the EU Commission’s study projects the annual demand to be 900 TWh in 2040 and 1,270 TWh in 2050. Whereas this report’s analysis projects the demand for hydrogen for 2045 to be within the range of 733 TWh to 1852 TWh.

A 2021 study conducted by European Hydrogen Backbone [56] estimates that the annual demand for green and blue hydrogen in Industry (for both the EU and the UK) will reach 692 TWh in 2040 and 983 TWh by 2050 [56]. Whereas this report projects the demand in industry in both EU and UK to range from 534 TWh to 711 TWh in 2045.

Figure 13 provides a full comparison between the results of this study and those of two external studies. The results estimated for this report are shown as a range of total projected annual demand of hydrogen for EU, for the years 2030 and 2045. The results of the other two studies are not shown as ranges; and the years for these studies are 2030, 2040 and 2050. It is also worth noting that this study includes demand for the heating sector, which is not accounted for in the other two.

Figure 13: Comparison of this study’s results with the literature

The comparison of these estimates is challenging as their geographical scope and timelines vary, with a number further differences in modelling methodologies.

Policy Gap Analysis

Our stakeholder engagement and desk-based research highlighted the following policy gaps. Further regulatory gaps can be found in Table 18.

In the United Kingdom, reserved matters are decisions taken by the UK Parliament, as opposed to devolved matters where devolved institutions, including the Scottish Parliament, hold decision making authority. As such, we have split our policy gap analysis into Scotland based, UK based and international policy gaps.

Policy Gaps in Scotland

Scottish policy gaps are set out below.

Lack of clarity on hydrogen trade strategy

Clear signals from the Scottish Government are required for the Scottish industry to prepare and make strategic decisions to enable successful trade.

Planning and permitting

Planning and permitting processes need to be faster and streamlined. Hydrogen projects typically require long lead times, due to infrastructure requirements as well as typical barriers to the implementation of innovative technology. This finding is in line with our stakeholder engagement and 2023 report commissioned by DESNZ [57]. Streamlining and accelerating the planning processes is key to alleviating investment barriers.

While our stakeholder engagement and desk-based research was conducted prior to the announcement of ‘the Planning Hub’ [58], this new body is anticipated to improve consenting speed and make the planning system more efficient for hydrogen projects.

Regional Strategic Planning

Stakeholder engagement highlighted that Scotland is home to diverse regions, with varied geographical environments. Blanket, national strategic planning risks overlooking localised requirements and optimal use cases =. Scotland needs regional hydrogen strategies that are integrated with a cohesive national strategy.

Increasing need for trials and demonstration projects

The hydrogen industry, especially the trade sector, will utilise new technologies, which still need to be proven and developed. Trials and demonstration projects are increasingly needed to build the case for these technologies.

Policy Gaps in the UK

As outlined above, some policy gaps relate to the UK Government as a reserved power, as opposed to the Scottish Government, as a devolved power. The policy gaps for the reserved power, in this case the UK government, are detailed below.

Hydrogen Trade Strategy

The UK is currently lacking a clear strategy on hydrogen trade as well as a holistic strategy incorporating natural gas, electricity and hydrogen. This is urgently required to provide clarity, allow for strategic decisions to be taken and stimulate investment.

The establishment of National Electricity System Operator (NESO) is a positive step towards solving this issue. NESO is expected to address issues regarding whole system strategy by integrating electricity, gas and hydrogen infrastructure into one energy system plan. NESO has developed whole energy system models, titled Future Energy Scenarios, which support planning and identify the opportunity for Scotland to be an energy exporter. This work should be expanded to include economic modelling on trade, culminating in a developed and full strategy.

Infrastructure

A clear commitment to a core hydrogen network, linking industrial clusters in Scotland, England and Wales is needed. More clarity on the timeline is key to improving investor certainty and get initial projects off the ground.

Dated and fragmented hydrogen regulation

Onshore hydrogen projects are currently regulated under the Gas Act 1986 and Planning Act 2008, with hydrogen generally being defined as a ‘gas’. Our stakeholder engagement suggested that current regulation is fragmented, with more concise and ‘net-zero-aligned’ regulation increasingly needed in the UK.

Hydrogen Production Business Model

Risk-taking intermediaries (RTI), market players who take ownership of the hydrogen molecules before selling it on to transporters or end users, need to be recognised as an eligible offtake option. Stakeholders warned that without the recognition of RTIs, large-scale and efficient hydrogen trade, transport and storage may not materialise. Additionally, the current allocation round set up of the HPBM has also raised a competitive element between projects. This reduces collaboration between key stakeholders. The UK Government should assess how they can reduce this competition driven fragmentation within current funding mechanisms.

Misalignment between UK and EU ETS

The UK and EU ETS need to be aligned to successfully foster low-carbon trade of goods. Clarity is urgently needed around the scope of inclusion for the maritime sector.

Review of Electricity Market Arrangements (REMA)

The current electricity market pricing structure needs reforming to help bring down prices. As electricity prices are a major driver of hydrogen production costs, reforms are critical to increasing uptake and improving competitiveness of UK hydrogen.

Wider and international policy gaps

Alignment between international policy is critical to facilitating successful trade between nations. International policy gaps are shown below.

Lack of clarity on emission factors

Standardised emission factors for alternative fuels (e.g. methanol) are needed. This is highly relevant to sectors such as maritime and aviation where synthetic fuels may play a major role. Standard values are needed for carbon accounting, from accredited sources, to ensure reporting consistency.

Misalignment between certification frameworks

Differences in low-carbon hydrogen certification frameworks create complexity in international trade. The development of mutually recognised standardised certification frameworks is essential to facilitate cross-border trade in hydrogen and its derivatives.

Conclusions

Scotland has significant opportunities in the production, use and export of hydrogen, its derivatives and products, particularly to nearby markets in England, Wales, and the European Union. England and Wales offer a large local market due to existing industrial demand, geographical proximity, and similar regulatory frameworks. The EU is also a potential market because its member states are unlikely to meet their own low-carbon hydrogen demand, creating an opportunity for Scottish exports.

While Germany and the Netherlands are anticipated to import significant amount of hydrogen and derivatives, the extensive infrastructure and harmonised certification frameworks necessary for international trade are not yet in place. Subsea hydrogen interconnectors are crucial for intra-European trade as alternative delivery methods and hydrogen derivatives are associated with substantially higher costs. Without such a pipeline, other renewable resource-rich regions, such as the Middle East, South Africa and South America, may outcompete Scotland in the European market.

For global trade, ammonia is expected to become the dominant hydrogen derivative due to its technical maturity, efficiency, and well-established global market. Other hydrogen transport methods, like liquified hydrogen, LOHCs and metal hydrides, are anticipated have a more minor role. The most suitable hydrogen derivative for export will depend on factors including scale of production, transport distance, infrastructure readiness and end use application.

Key UK and EU industrial sectors such as chemicals, aviation, and steel are well-positioned to use hydrogen and hydrogen products directly, supported by rising carbon prices and emerging policies like the Sustainable Aviation Fuel mandates in the UK and the European Union. Although synthetic methanol will play a key role in decarbonising industrial use and maritime projects, uncertainties remain around maritime policy and biogenic CO₂ availability.

As low-carbon ammonia markets and propulsion technologies mature, the maritime sector is projected to transition from ammonia to methanol in the medium to long term. Hydrogen has also been found to be critical for the decarbonisation of the iron and steel industry, with the majority of steel plants expected to use directly reduced iron (DRI) technology.

The success of international hydrogen trade will depend on robust infrastructure, emission trading schemes, and the timely implementation of the CBAM, alongside mutually recognised certification frameworks.

Recommendations

1. Stimulate demand by improving alignment – With carbon prices being among the strongest demand-side incentives, the Scottish Government could work together with the UK Government and the EU to maximise its benefits. As pointed out by stakeholders, the UK and EU Emissions Trading System need to be aligned to avoid potential carbon taxes on UK products including maritime fuels. The timely launch of the UK Carbon Border Adjustment Mechanism (CBAM) is also critical to stimulate demand domestically and achieve better alignment and consistency with the EU policy framework. Section 8 of the report discusses these policies, and more, in higher detail.
2. Stimulate demand by supporting trials and demonstration projects –The Scottish Government is encouraged to continue its approach with supporting hydrogen demand projects through subsidy schemes, such as the Hydrogen Innovation Scheme, helping end users overcome barriers to investment. More trials and demonstration projects are key to create learnings, improve investor certainty and get initial projects off the ground.
3. Support infrastructure – Scotland should support key new-built and repurposed infrastructure projects including a core UK hydrogen network, ports and terminals (see Section 5.2). This includes working with the UK Government to give developers more clarity on the timeline of a core hydrogen network and how this will link with UK ports and terminals. There should also be an equal amount of focus on developing demand- and storage-based infrastructure, like hydrogen boilers, refuelling stations and salt cavern storage.
4. Enhance competitiveness of Scottish hydrogen –To effectively compete with renewable rich regions, Scotland needs to meet a lower levelised cost of hydrogen. This is because the main contributor to the levelised cost of hydrogen is electricity price. High electricity prices are identified as one of the biggest weaknesses in Scotland’s hydrogen ambitions, as laid out in section 6.2. While the power of devolved administrations is limited, the Scottish Government is recommended to (1) commission research into alternative electricity market arrangements and (2) work with the Office of Gas and Electricity Markets (Ofgem) and the UK Government, representing the Scottish industry from an evidence base position.
5. Reform the planning and permitting regime and ensure safety case is developed – With Scotland having a longer and more complex planning and permitting framework compared to other industrialised countries, developers need more guidance. The Scottish Government should look to streamline these processes where possible to avoid unneeded congestion and accelerate decarbonisation. Work with the Health and Safety Executive (HSE) to ensure that the safety case for hydrogen is developed in a timely manner and disseminate the results effectively.
6. Optimise low-carbon policy frameworks – While current policy is designed to get initial projects off the ground, our research found that the Hydrogen Production Business Model needs to be optimised and designed considering interactions with other low-carbon policy frameworks, such as the Contracts for Difference Scheme, Hydrogen T&S Business Models and the H2P Business Model. The UK Government allowing risk-taking intermediaries in subsequent allocation rounds is critical to strengthen the hydrogen supply chain and unlock domestic hydrogen trade.
7. Co-ordinate with the EU –Infrastructure projects have long associated lead times and limited flexibility once approved. Therefore, coordinating infrastructure deployment with the European Hydrogen Backbone and port infrastructure is essential. More coordination with the EU, in the form of trade policies, was also one of the key takeaways and a commonly brought up point in the stakeholder engagement that Gemserv conducted. Key findings from the stakeholder engagement are discussed in Appendix G.
8. Continue progress on low-carbon – A standardised low-carbon hydrogen standard is critical to the success of hydrogen trade. The Scottish Government is recommended to work with the UK Government, European bodies and other international stakeholders to accelerate the harmonisation or the mutual recognition of low-carbon certification frameworks.
9. Engage local communities – Public perception has been seen to be a critical aspect in the successful implementation of hydrogen as a technology. The Scottish Government should continue to engage with local communities and improve the public understanding hydrogen’s role in a net zero energy system as well as the stringent safety and regulatory measures undertaken in implementation. The Scottish Government could also look at forming a strategy of how best to disseminate the benefits of hydrogen trade to local consumers.
10. Set out strategy on hydrogen trade – The Scottish Government could work with the UK Government on a clear strategy on how hydrogen export, and potentially import capacities, are planned to be developed.

Appendices

1. Hydrogen derivative and product assessment

Hydrogen, pipelines, derivatives and low-carbon alternatives

Economic implications

As shown in Figure 14 below, repurposed 48-inch pipelines are likely to have the lowest levelised cost of delivering hydrogen [26]. Since there are no existing pipelines between the Scottish mainland and the proposed hydrogen export markets in Europe, this option would likely involve the construction of a large length of new 48-inch pipeline. The construction of pipelines over long distances, however, would require a significant initial investment of both time and capital. Therefore, conventional tanker transport may provide a short-term solution, especially in cases where scale, distance or the end use case would not justify pipeline construction [59]. From a market perspective, our stakeholder engagement and existing research [60] [61] suggest that compressed pipelines are critical to ensure the competitiveness of Scottish hydrogen in European market. This is because alternative delivery methods and hydrogen derivatives are associated with substantially higher costs. Without a subsea pipeline, other renewable resource-rich regions, such as the Middle East, South Africa and South America, may outcompete Scotland in the European market.

Owing to its higher volumetric energy density of 70.85 kg/m³ [62], it is possible to transport the same amount of liquified hydrogen in a smaller tanker compared to gaseous hydrogen. Compared to compressed hydrogen pipelines, this option is still relatively expensive per volume of hydrogen transported, with the liquefaction process estimated to add up to almost half the total cost of hydrogen transport [63]. Liquified ammonia has been shown to be the lowest cost of selected hydrogen derivatives over long distances [26]. When ammonia is used directly as a feedstock, it is not necessary to reconvert the ammonia to hydrogen upon arrival.

Direct use of hydrogen derivatives is further discussed in section 4.2. Our research used offshore high-voltage direct current interconnectors as a reference point, as they are also suitable to alleviate curtailment issues to some extent. Despite no ‘conversion costs’, transporting renewable electricity through HVDC cables could have higher costs compared to repurposed hydrogen pipelines due to efficiency and flexibility restrictions, described within Section 5.1.1.2.

Figure 14: Levelised cost of delivering hydrogen Source: International Energy Agency (IEA) (2022)

Technical feasibility

Subsea high voltage cables are highly mature, with a technology readiness level (TRL) of 9 and nine electricity interconnectors already connecting Great Britain to neighbouring countries [64]. However, congestion issues, relatively low efficiency over long distances and the lack of long-term flexibility could make electricity interconnectors less suitable to export larger amounts of renewable energy compared to hydrogen technologies [7] [65] (Table 15)

Transporting hydrogen through new-built pipelines is a mature technology (TRL 9), with more than 2,000 km of pipelines operational in Europe [26]. Given limited commercial deployment, repurposed pipelines have lower technical maturity (TRL 7) [26]. Investigation into the repurposing of networks is ongoing in the UK as part of National Gas Transmission’s FutureGrid project [66]. Scotland has 17,000 miles of gas pipeline [67], with an additional 100% hydrogen North Sea pipeline being considered as part of the Hydrogen Backbone Link. This would enable export of hydrogen from Scotland to Germany through a 10 GW hydrogen pipeline by 2045, transporting 2.4 kt of hydrogen per day [4] [68]. Liquified hydrogen has been used for a long time, with the first liquefaction taking place in 1898 [69]. As liquified hydrogen has not been produced on a commercial scale, it has a TRL level of 8 [70] [63].

Although conversion and reconversion processes are needed, the simpler handling and higher hydrogen density of hydrogen derivatives make them more attractive. While some liquified ammonia could boil off during transport (approximately 0.098 % /day) [63], ammonia loss is less significant compared to liquified hydrogen, given the relatively high boil point of -33 °C. Stakeholders agreed that while low-carbon hydrogen production is in its infancy, ammonia production and shipping has competitive advantage in technical maturity compared to other derivatives. While no ammonia or liquid hydrogen port projects have been announced in Scotland, some of the existing infrastructure, for example LNG and LPG terminals, can also be repurposed to reduce capital costs [71]. Strategically important Scottish ports are discussed in further detail in Table 11. The final step in the value chain is ammonia cracking, splitting ammonia into hydrogen and nitrogen molecules. Ammonia crackers are not as mature as ammonia synthesis plants and have an overall TRL between TRL 4 and 6 [72].

The main technical advantage of LOHCs, for example methylcyclohexane (MCH) and dibenzyl toluene (DBT), is that they are compatible with existing liquid fuel assets, with no boil off during shipping. While interest in LOHCs is limited in Scotland, some UK-based developers are investigating this technology. Magnesium hydride has a volumetric H₂ density of 106 kg H₂/m³, which makes it a suitable alternative to ammonia in ports that do not allow its import or export, due to stringent safety regulation. Magnesium hydride is easier to handle than ammonia, and magnesium as feedstock is widely available, reducing total costs. Some stakeholders highlighted the increasing need for the HSE’s updated guidance on hydrogen safety, with most stakeholders mentioning the lack of guidance on hydrogen planning and permitting as a significant bottleneck. Several UK-based projects, including, HyDus [73], HEOS [74] and HydroStar [75], are investigating metal hydride technologies. Further research is being undertaken to increase the uptake efficiency and the dehydrogenation process, which does not require high temperatures. Our stakeholder engagement suggests that strategic co-location of hydrogen derivative plants with other heat-intensive processes could offer additional efficiency gains through heat recovery. Strategic planning with holistic and regional approach, however, is critical to unlock these opportunities. Technical advantages and disadvantages are displayed in further detail in Table 12.

Sustainability

Overall greenhouse gas (GHG) emissions associated with hydrogen and derivative transport are highly sensitive to the fuel and technology used for the conversion, transport and reconversion processes, also known as hydrogenation and dehydrogenation. Among all hydrogen and derivative transport methods, compressed hydrogen pipelines are associated with the lowest greenhouse gas emissions [76], with low energy requirement and compression being easy to decarbonise. Other derivatives, like ammonia and LOHC, require more energy, with some of the processing and transport methods being hard-to-decarbonise [77]. As Haber-Bosch synthesis accounts for approximately one third of all energy consumed in the ammonia production process [78], it is critical that any future ammonia plants are designed to run on low-carbon energy. However, only a limited amount of work has been done on electrifying ammonia synthesis and cracking [79]. A 2022 E4Tech research paper found that low-carbon ammonia would not necessarily meet the UK Low Carbon Hydrogen Standard even if electricity were to be used for ammonia synthesis [76]. Ammonia and most LOHCs are toxic to humans and marine ecosystem, with further sustainability and environmental concerns detailed in the Table 14.

Industrial feedstock

Economic implications

Low-carbon hydrogen can be integrated into ammonia and oil refining processes without significant modifications to existing equipment. This infrastructure readiness may offer cost benefits. As highlighted by stakeholders, there is better economic case for using ammonia directly compared to reconverting it to hydrogen. This is because costs and efficiency losses associated with reconversion, also known as dehydrogenation, can be avoided [80]. In Table 4, ammonia production and refining are not assigned economic RAG ratings due to the lack of a viable low-carbon alternative for reference. The future cost competitiveness of synthetic methanol remains uncertain, given the unknowns surrounding hydrogen and biogenic CO₂. Existing research, however, suggests that bio-based methanol could be produced at a cost up to 55% lower than synthetic methanol [13]. Conventional methanol plants can also operate on bio-feedstock. The economic competitiveness of green steel varies, with a RAG rating of green and amber, depending on the chosen technology. Despite high costs, DRI technology is expected to capture a growing share of the green steel market due to its carbon neutrality. As sustainability becomes a priority, hydrogen-based iron reduction will likely become more cost competitive, gradually reducing reliance on highly polluting blast furnaces [81].

Technical feasibility

In contrast to ammonia and refining plants, synthetic methanol production necessitates significant infrastructure investment or substantial upgrades. The process requires the capture and storage of high purity biogenic CO₂, with the technology currently at a TRL of 8-9 [13]. These plants operate at high efficiencies, ranging from 89 to 95% [82]. However, multiple stakeholders have emphasised the growing need for strategic planning, especially on regional scale, due to the geographical misalignment between biogenic CO₂ and hydrogen supplies which is a challenge to efficient production. For steel production, electrolytic hydrogen has been successfully demonstrated for DRI, but it has not yet reached commercial scale (TRL 7) [83]. Currently, it is estimated that less than 1% of steel in Europe is produced using DRI [84], with the majority of planned DRI projects yet to be operational [85]. Steel production in Scotland has declined in recent years, with annual output falling below 6,000 tonnes of crude steel [86]. Although some plants have outlined their decarbonisation strategies, the path to fully decarbonising Scottish steelmaking remains uncertain. When asked about technical challenges, most stakeholders were not concerned about early-stage technical maturity. Stakeholders suggested that the complexity of the planning and permitting process and the length of consideration are more significant bottlenecks in project development.

The use of low-carbon hydrogen in oil refining and fertiliser production presents minimal technical challenges, as the transition primarily involves fuel switching. INEOS intends to use low-carbon hydrogen, starting as early as 2029 [87]. However, with no ammonia and fertiliser production facilities in Scotland, interest in ammonia production is limited. Meanwhile, plans to establish a renewable methanol plant in Scotland by GEG and Proman are underway [88].

Sustainability

Hydrogen has been used as industrial feedstock for decades, with strict adherence to safety regulations by producers and users. Beyond the environmental benefits associated with fuel switching and decarbonisation, hydrogen also plays a crucial role in desulphurisation which prevents sulphur oxide emissions and reduces the risk of acid rain. While some fugitive emissions may occur (see Table 14), regulations and commercial incentives are in place to minimise these. Further details on environmental impact are detailed in Appendix C.

High temperature heat 

Economic viability

Hydrogen has a high gravimetric energy density of 120 MJ/kg compared to 44 MJ/kg of natural gas [89], making it an attractive option for decarbonising high temperature industrial heat. However, hydrogen’s low volumetric energy density compared to natural gas makes it more expensive to store and transport, due to the increased capacities required. For this reason, among others, transitioning to hydrogen as fuel comes with significant costs. For example, converting a furnace in the basic metals sector to hydrogen would cost approximately £730,000 for 10 MW of capacity [10]. It is estimated that £2.7 billion in capital investment would be required to convert UK industrial sites and equipment. CCUS is also considered relatively high cost even though costs are expected to decline with technology maturity [90]. Our stakeholder engagement confirmed that CCUS technologies will become more cost-effective with scale and concentration of demand. The carbon capture process itself is the most expensive component accounting for 80% of the total costs [90]. On the contrary, bio-based fuels are widely available, scalable and cost-competitive in certain locations. Our stakeholder engagement highlighted that while bio-based fuels are widely available today, feedstocks are limited, preventing larger-scale and widespread adoption in the future.

Technical feasibility

Most industrial equipment, such as boilers, kilns, ovens, furnaces, has been demonstrated to be compatible with hydrogen through the Hy4Heat project [10]. While the technology is available, it has yet to be demonstrated at a commercial scale (TRL 7-8; industrial fuel switching). Minor technical challenges persist, including issues with pipe sizes, flue gas composition and different heat transfer characteristics [91]. Additional details on hydrogen heating technical challenges are in Table 13. Many natural gas-fire gas furnaces can be retrofitted, with only certain components requiring modification [91] [92]. However, retrofit options and associated GHG and cost savings depend on the end use sector and the complexity of the industrial site. Our stakeholder engagement confirmed that more trials and demonstration projects are needed to increase the technical readiness of hydrogen technologies and create learnings in a Scottish context.

CCUS systems can be integrated with existing boilers and heaters [93]. However, carbon capture infrastructure requires large investment. The UK’s geological advantage and access to depleted hydrocarbon fields provide a competitive advantage for carbon storage [94]. As pointed out by stakeholders, scale is critical for operating CCUS systems cost-effectively. Therefore, these systems must be strategically located, near concentrated demand, favourable geology and potential biogenic CO₂ offtakers. Although large-scale CCUS projects are not yet operational in Scotland, the Acorn Project has advanced directly to Track 2 of the UK Government’s Cluster Sequencing Programme. By reusing the existing hydrocarbon infrastructure, the Acorn project aims to capture and store between 5 and 10 Mtpa of CO₂ under the seabed by 2030 [95].

Table 9: Technology Readiness Level of selected high temperature technologies

Solid biomass is a well-established technology, with most biomass boilers, kilns and furnaces achieving a TRL of 9 [99]. While the majority of biomass is currently used to generate electricity, over 37% is utilised to produce heat [100]. Given that CCUS and hydrogen technologies are not yet commercially available, many industrial plants aiming for long term decarbonisation opt for biomass. Unlike hydrogen, biomass can be stored at ambient pressure and temperatures. However, biomass technologies are generally unsuitable for direct heating applications, such as kilns, furnaces and dryers, as they may affect the product quality [99].

Sustainability

Burning hydrogen does not produce CO_2, but it can generate increased levels of nitrogen oxides (NOx) compared to natural gas combustion due to the higher temperatures used [101]. Nitrogen oxides are a mixture of gases, worsening air pollution, impacting human health and, reacting with other gases, indirectly contributing to global warming. However, research indicates that the higher stable combustion temperature of hydrogen may offset NOx emissions [102]. This is because the increased air to fuel ratio enabled by hydrogen leads to lower combustion temperatures which in turn reduces NOx emissions [102]. While CCUS technologies cannot capture 100% of CO₂ emissions, pairing them with biomass kilns and furnaces may result in negative emissions. Additional details on sustainability benefits and challenges are provided in Table 14.

Transport

Economic implications

For LDVs, Fuel Cell Vehicles (FCVs) achieving cost parity with fossil fuel powered LDVs before 2040 will be challenging, unless the fuel cell costs decrease due to higher volume production. When looking at 5-year total cost of ownership, fuel cell powered and battery electric powered LDVs will likely be close or marginally lower than fossil fuel powered LDVs by 2040 [103]. The Advanced Propulsion Centre conducted a battery and fuel cell vehicle cost comparison for a range of vehicle types. Findings included that fuel cell powered vans will be the preferred technology type by 2030 [104].

Fossil methanol has an established global market, with synthetic methanol production growing each year [105]. Existing ships and vessels that run on liquid fossil fuels, like diesel and kerosene, can be retrofitted to run on low-carbon, synthetic liquid fuels, like methanol, allowing owners to avoid the capital cost of a new ship. Although sales of methanol dual-fuel ships have significantly increased in recent years [106], the high cost of synthetic methanol may change commercial incentives [107]. Our stakeholder engagement also suggests that ammonia will be the dominant maritime fuel in the short and medium-term due to the lower cost of the fuel. This is in line with the analysis of the IEA estimating the cost of synthetic methanol production to be 25 to 100% higher than the production cost of low-carbon ammonia [107]. The difference in fuel costs is partially due to the high cost and limited availability of biogenic CO₂, making methanol ships uncompetitive in the long-term, especially once ammonia technologies are mature. This is despite the higher transport and storage cost of ammonia, requiring cooling and compliance with a range of national and international regulations.

According to the International Air Transport Association (IATA) the average price of jet fuel in 2022 was roughly £3.18 per gallon, a 149% increase on the previous year, yet comparatively, in 2022, the current average price of SAF within the US was £7 per gallon [108]. While the IATA estimates that all SAF products are 2-4 times more expensive than alternative aviation fuels [108], costs could reduce with the emerging SAF mandate.

Technical feasibility

Hydrogen fuel cells have faster refuelling times than Battery Electric Vehicles (BEVs), making them well suited for long heavy-duty trips [16]. Fuel cells also have other potential applications in maritime, rail and aviation (HyFlyer) sectors. The Scottish Government has funded multiple hydrogen buses in Aberdeen that have been successfully implemented since 2015 [109]. On the whole, fuel cells have a high TRL, however this can vary slightly by use case. For example, the Aerospace Technology Institute label a generic fuel cell as TRL 8, with a fuel cell in aviation use cases at TRL 5 [110].

Ships can be retrofitted for ammonia engines easier than for fuel cells, which need a complete makeover of the engine infrastructure. Ammonia blends of 70% have been successfully implemented [111] in certain engines. The energy transfer chain of ammonia has a number of conversions resulting in efficiency losses. From the initial renewable energy produced, 17% will make it to the ship’s propeller [112]. On the other hand, it is more complicated to produce synthetic fuels in large quantities limiting the long-term applications. Ammonia must be stored at -33◦C. This gives e-fuels a storage advantage, as the conditions are much milder and not different to the current fuels used. The IEA’s report on International Shipping reports that in 2022, 90 (11% by tonnage) new-build orders were for ammonia-ready vessels, 43 (7%) were for methanol vessels and 3 were for hydrogen-ready vessels [113]. SAF encompasses a range of technologies or SAF production pathways, detailed in Table 10.

Table 10: Technology readiness of transport technologies

Sustainability

Whilst SAFs release carbon when burned, they could reduce carbon emissions by 80% over the lifecycle compared to traditional jet fuel [114], while having similar combustion characteristics and safety considerations. Ammonia burns less easily and is less flammable than conventional shipping fuels, and therefore is safer from a health and safety perspective [115]. Hydrogen fuel cells do not result in any emissions of greenhouse gases when in use [116]. Further sustainability benefits and challenges are detailed in the Table 14.

Power generation

Economic implications

The capital cost associated with large scale hydrogen peaking plants is estimated to be between £350 and £600 per kW, whereas capital costs associated with fossil fuel based peaking plants is between £300-600 per kW [117] [118]. The overall cost of electricity, however, will depend on several factors, for example, load factor, efficiency of the turbine, heat and water recovery [119]. While large scale hydrogen power plants can technically provide both mid-merit and peaking generation, they are expected to be cost competitive when running as a peaking plant and below a load factor of 20-30% [118] [120]. This is due to higher operating costs compared to low-carbon alternatives. Despite additional costs, there is an economic case for retrofitting existing natural gas power plants with CCS (Table 17). This is because retrofitting is estimated to extend the lifetime of a power plant by 10 years, resulting in substantially lower capital costs [23]. The estimated cost of retrofit is around £110 per kW compared to the new-build gas turbine’s capital cost of £740 per kW [120]. Due to increasing scale and simplification, it is estimated that the cost of CCS-power plants could reduce by 45% after the first three installations, with technical innovation leading to an additional reduction of 5-10% thereafter [121]. With widely available biomass supply and highly mature technology, unabated biomass generation is currently the most prevalent among the selected technologies. However, as CCS technologies become commercially available, unabated biomass generation is anticipated to be phased out. This is due to the relatively high cost of power generation. While retrofitted hydrogen plants could reach a levelised cost as low as £65 per MWh in 2035, the Contract for Difference of biomass plants guarantees £100 per MWh (2012 prices) [23]. The levelized cost for unabated gas plants may reach £170-£180 per MWh while gas CCS plants’ levelized costs are estimated to be £75-£90 per MWh [23]. Despite this challenging economic case, biomass plants coupled with CCS technology are expected to have high potential due to substantial carbon benefits. While the cost of hydrogen-fired turbines could reduce over time, they are expected to be used for low load factor operation, with CCUS-enabled power generation running on higher load factors.

Technical feasibility

While only minor alterations are required to existing gas power plants to reach hydrogen/gas blends around 70% [122], 100% hydrogen power plants have more potential in the long term due to higher carbon benefits. Retrofit to 100% hydrogen plants is also technically feasible, with a few technical challenges including changes to pipes and combustors due to differences in hydrogen’s volumetric density. Ammonia is the least mature power generation technology among the four. A few projects have demonstrated the viability of co-firing up to 20% and 70% with coal and natural gas, respectively [123]. Some technical challenges such as flame stability, and the low combustion speed of ammonia do not only make ammonia-fired power generation less efficient than the baseline but also result in incompatibility with larger gas-turbines [124]. The main technical advantage of biomass power plants is that existing coal power plants can be easily retrofitted to run on biomass. Given high technical maturity, capacity for electrical generation from biomass in the UK reached 12% of all capacity in 2023 [125]. Despite high hydrogen potential, there is limited experience with hydrogen power generation in Scotland. The Peterhead Power Station is planned to be coupled with CCUS technology as part of the Acorn project, positioning the facility as one of the first CCUS-enabled gas power plants. In addition, there are eight major diesel generation sites in Scotland used as backup supply for remote locations [64] [126]. A few hydrogen power projects, like the Kirkwall Airport CHP, are operational in Scotland, but further trials are needed, particularly on remote Scottish Islands, to provide learnings of this sector in a Scottish context, according to our stakeholder engagement. Further technical details can be found in Table 17.

Sustainability

Main sustainability concerns include CO₂ leakage rate from underground reservoirs, ammonia’s toxicity and NOx emissions. Due to high carbon benefits, a 2018 CCC Biomass report concluded that available biomass should be used with BECCS applications ‘to the maximum extent possible’ [127]. Further sustainability challenges and benefits are detailed in Table 14.

1. Offtaker Market Assessment

Existing demand

Figure 15: Import of hydrogen in 2023 in selected countries [33]

Figure 16: Value of ammonia trade in EU, Belgium, Germany and the Netherlands. Source: Eurostat

Infrastructure log

Table 11: Infrastructure opportunities in Scotland, the rest of the UK and selected European countries

1. Techno-economic tables

Table 12: Technical table of hydrogen carriers

Sources: [128]; [129]; [130]; [131]; [77]; [132]; [133]

In order to attract investment, hydrogen transport must be financially profitable within a specifically defined niche. A number of methods of hydrogen transport are available, all with differing properties which determine how cheaply and safely the hydrogen can be transported. Although hydrogen is incredibly dense by mass, it takes up a lot of volume, which makes it expensive to transport. It can therefore be compressed or even liquified to decrease the price of transport, or alternatively it can be transported in the form of other substances that contain a large amount of hydrogen but have different properties (for instance density) that make them cheaper to transport. Physical properties such as the volumetric density and storage temperature of each carrier are important factors that would have to be accounted for in the supply chain. On the other hand, technology readiness level (TRL), market readiness level (MRL) and commercial readiness level (CRL) are all technoeconomic properties that reflect how mature each technology is and whether the carrier is likely to be financially viable. Technoeconomic properties are not fixed in the same way as physical properties and so as the technologies develop, certain carriers may become increasingly viable. Ultimately both physical and technoeconomic properties of each transport option must be weighed up and used by decision makers to predict the best course of action.

Hydrogen heat technical challenges

Table 13: Technical challenges with high temperature heat equipment

Sources: [134]; [135]

Environmental log

Table 14: Environmental log

Table 15: Technical table of hydrogen derivative technologies

Table 16: An overview of SAF production pathways [77]

Table 17: Techno-economic table of power generation technologies

1. Policy tables

UK Regulatory Barriers

Table 18: Policy gaps in the UK

International Hydrogen Policy Log

Table 19: International Hydrogen Policy Log

1. Demand mapping methodology

Overview of Approach

The demand mapping analysis is carried out for five regions and six sectors for the years 2030 and 2045. The analysis only considers low-carbon hydrogen and derivate demand, and not hydrogen demand that does not meet sustainability criteria in the region. The regions covered are chosen based on the regional mapping carried out earlier in this project and include:

• The EU
• Germany
• Belgium
• The Netherlands
• Scotland, England and Wales

The sectors covered are the ones in which hydrogen may play a role, with a focus on sectors where the role of derivatives and products could be greatest. These include:

• Industry
• Power Generation
• Road Transport
• Aviation (with a focus on power to liquid fuels)
• International Maritime (with a focus on ammonia and methanol)
• Heat

The analysis has taken a high-level approach to develop three scenarios (low, central and high) for each region and sector. In general, the approach taken for the EU and EU national geographies aligns due to similar overarching policy and data sources. While the approach for England and Wales often differs due to different policy and assumptions.

The EU and EU National Geographies (Germany, Belgium and The Netherlands) Sectoral Approach

Industry

The demand mapping for industry utilises data from Eurostat Simplified Energy Balances [171] which gives total demand for energy by industrial sector in the EU and the three EU nation states considered. The change in energy demand and suitability for hydrogen in each sector is based three scenarios developed in N-ZIP model produced for the Climate Change Committee (CCC) [172]. While this source does not give data based on EU suitability, it does give broad indications of sectoral suitability for hydrogen compared to alternatives and is therefore used to produce a low, central and high range of suitability.

An alternative approach has been used for sectors that currently use hydrogen (predominantly the chemicals sector and the refining sector). This is partially due to the EU’s target to ensuring 42% of hydrogen use meets RFNBO criteria in 2030 [54], however it is worth noting that refining is excluded from this target. The approach for the chemicals sector is to use a combination of current estimates of hydrogen demand [173], and calculating the proportion of low-carbon hydrogen that is required to meet the RFNBO target, while assuming the CCC’s reduction in energy demand for the sector by 2030.

While the 42% target does not apply to refineries, it is expected that refining will be an early user of low-carbon hydrogen due to current demand, experience in handling hydrogen and RFNBOs used in refining contributing to RFNBO targets in the transport sector. Hydrogen Europe estimate that there are 1.2 Mt/year of clean hydrogen projects announced in the refining sector by 2030, representing 26% of current hydrogen demand [174]. Furthermore, current hydrogen demand makes up approximately 40% of total energy demand in the sector. For this reason, estimates of total energy demand that is clean hydrogen in 2030 of 5, 10 and 15% have been selected for 2030. All scenarios assume refineries operate on clean hydrogen by 2045.

Table 20: Trajectory of proportion of clean hydrogen used energy for the years 2030 and 2045

Industrial demand is broken down by product in 2030 based on applying RED III mandates to historic ammonia and methanol demand by region, developing scenarios based on historic high and low demand levels. Demand for 2045 is estimated, by assuming that all hydrogen demand for these products is low-carbon.

Power Generation

Hydrogen’s role in the power sector is uncertain and depends on policy incentives, infrastructure and technology readiness of turbines. This analysis assumes that total electricity generation in 2030 for the EU, Germany, Belgium and The Netherlands follows the estimates of generation in the MIX-CP scenario developed for European Green Deal Analysis [175]. This scenario was selected as it most closely aligns with policy measures that were agreed upon.

The analysis assumes that total electricity generation in 2045 follows the midpoint of the of the 2040 and 2050 values for the two scenario estimates in a recent European Commission report considering energy infrastructure configurations in Europe [176]. This estimate is used to develop a compound annual growth rate assumption of 4.2% for electricity generation in the EU between the 2030 estimate and 2045 assumption. This compound annual growth rate is applied to regional estimates in the MIX-CP scenario for Germany, Belgium and The Netherlands to estimate annual electricity generation in 2045.

It is broadly accepted that an electricity grid that is dominated by intermittent renewables will require low-carbon dispatchable generation to meet demand at times of low renewable generation. The CCC estimate that in the Balanced Pathway, 13% of electricity demand is met by low-carbon dispatchable power generation in 2045 [177]. However, the split between hydrogen and other options such as gas with CCUS or BECCS is unknown at this stage.

For the purposes of this analysis, the following proportions of electricity generation that are met with hydrogen are assumed. These include no hydrogen to power in 2030 due to the requirement for large scale hydrogen storage to be in place to operate hydrogen power at low load factors, which is its optimal role in the power system [178]. It is unlikely that there will be access to sufficient volumes of hydrogen storage in the 2030 timeframe due to the long lead times for large scale geological hydrogen storage [179]. Hydrogen power generation is assumed to have an efficiency of 48% [180].

Table 21: Proportion of hydrogen in total power demand

Road Transport

The road transport analysis focuses on vans, buses and HGVs given that heavier vehicles are more suited to hydrogen and lighter vehicles are more suited to battery electric drivetrains. The low and the high scenario are based on the proportion of road transport energy consumption that is hydrogen in 2030 and 2045 in FES 2024 in the highest and lowest hydrogen deployment scenarios. The central scenario is estimated as the midpoint between these upper and lower bounds. The estimated demand for transport by these vehicle segments in 2030 is taken from the MIX-CP Scenario [175], for the EU, Germany, Belgium and The Netherlands.

Table 22: Hydrogen Proportions of Energy Demand for Bus and Coach Transport

Table 23: Hydrogen Proportions of Energy Demand for Heavy Goods and Light Commercial Vehicles

Aviation

The analysis on aviation focuses on e-fuels which are based on hydrogen combined with captured carbon. The analysis utilises estimates of future aviation fuel demand for the EU and the PtL sub mandate to estimate e-fuel demand in 2030 and 2045, based on a report from the European Union Aviation Safety Agency [181]. The value for total fuel demand in 2045 is estimated by taking the midpoint of the 2040 and 2050 values. This is used to estimate the central demand estimate.

Table 24: Projections for supply of SAF

The energy content of these e-fuels is then estimated using the value of 43 MJ/kg [182] to develop estimates in TWh. Both low and high scenarios assume the same mandate for PtL, but varying levels of fuel demand based on the EASA’s low and high aviation scenarios [181].

Table 25: Multipliers on base case, by scenario

The national estimates for Germany, Belgium and The Netherlands are estimated based on national airport traffic data in 2023 [183]. This assumes that the current mix of air traffic data remains constant over time.

International Maritime

The analysis focuses on international maritime due to its greater suitability for hydrogen, derivatives and products than domestic maritime. This is due to the longer distances travelled in larger ships for international maritime which is less suitable for electrification. The decarbonisation route for ships is uncertain and could be met with biofuels or synthetic fuels. Transport & Environment (T&E) have estimated different routes to decarbonisation that comply with the EU’s FuelEU policy [184]. Note that the analysis carried out for T&E was designed for containerships and different shipping segments may select different decarbonisation routes. However, the authors of the report deemed it to be a good enough proxy to provide a high-level estimate of the entire international shipping sector.

These T&E scenarios are used to estimate the upper and lower bounds of e-fuel deployment in 2030 and 2045. The central scenario is derived as the midpoint of these bounds. The EU’s policy ensures that there is a minimum of 2% RFBNOs from 2034 onwards.