Interactive Energy Performance Certificate (EPC) user interfaces could allow householders to better assess potential retrofit measures, which could in turn prompt households to undertake energy efficiency measures and switch to clean heat systems.

This report aims to inform Scottish Government whether it would be beneficial to incorporate data or functionality into the national EPC register to support potential EPC interactivity.

The research explored a number of existing tools that offer a level of interactivity with EPC-like outputs and also involved a desk-based literature review.

Findings

Three levels of potential interactivity were identified to consider implementing in relation to EPCs:

1. Simple interaction, where no new user data and no integration with a calculation engine are required.
2. Medium interaction, where no new user data is required, but integration with a calculation engine is required.
3. Detailed interaction, where customised user behaviour and occupancy inputs could update outputs via integration with an enhanced calculation engine.

No direct evidence was found to support whether simpler or more detailed interaction is more likely to prompt households to retrofit.

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.

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.

There are a number of existing tools that already deliver energy advice to households, which have varying levels of interactivity and customisation.

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.

For further information please read the report.

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

Image credit: Photo by Laurentiu Morariu on Unsplash

 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).

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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. ↑

   
   

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.

This research reviewed, assessed, and ranked the potential of technologies that could enable cost-efficient domestic and international trade of hydrogen, as well its derivatives and products. The report also identifies offtake sectors and countries, assesses the scale of demand in potential markets, and identifies gaps and opportunities in domestic and international policy.

The researchers 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.
• 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.

Hydrogen derivatives

• Subsea hydrogen pipelines are critical to enhancing the competitiveness of Scottish hydrogen for trade within Europe.
• Ammonia is expected to be the dominant hydrogen derivative in the medium to long term for global trade.

Hydrogen products and end use cases

• Industry 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 will be able to use hydrogen derivatives and products directly, avoiding substantial costs on reconversion.
• Synthetic methanol will be key to decarbonising existing industrial uses of methanol and in initial low-carbon maritime projects.
• Hydrogen is expected to play a significant role in power generation in the long term.
• Hydrogen-based Sustainable Aviation Fuels (SAF) are well-placed to decarbonise the aviation sector.
• The main low-carbon alternatives to hydrogen include Carbon Capture, Utilisation, and Storage (CCUS) and bio-based technologies.

For further details, please read the report.

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

Image credit: Dave from Pixabay

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.

Table 26: Proportion of international shipping demand that is e-fuels

These fuel proportions are applied to the estimated energy demand for international shipping. This is calculated using the CP-MIX scenario as this complies with the fit-for-55 regulation and most closely follows the current policy structure of the energy scenarios produced by the EU Commission [175]. As this scenario only produces estimates to 2030, the growth rate for international shipping energy demand for each region between 2025 and 2030 is applied to the period 2030 to 2045 to estimate international shipping energy demand in 2045. This is deemed appropriate as applying this carbon reduction trajectory from 2025-2030 to the emissions metric results in gross emissions of approximately 14% for the EU in 2050, which should be compatible with achieving net zero provided sufficient greenhouse gas removals are in place.

Heat

The demand for hydrogen in residential heating is highly uncertain and could be significant, or non-existent in 2045. For this reason, and a lack of policy certainty, high level assumptions have been made for hydrogen deployment for heat. It is likely that due to the high efficiency of heat pumps, hydrogen heat would, at most, play a supplementary role in the heating mix. As with other sectors, the residential energy demand is estimated using the MIX-CP scenario and applying the 2025-2030 (negative) growth rate forward to 2045.

Table 27: Proportion of residential energy demand that is heat

Approach for England and Wales

Industry, Power Generation, Road Transport and Heat

The approach for the industrial, power generation, road transport and heating sectors for England and Wales utilises Future Energy Scenarios (FES) 2024 [185]. This contains three net zero compliant pathways for a decarbonised Great British energy system. In general, Electric Engagement is used for the low scenario, Holistic Transition forms the central scenario and Hydrogen Evolution is used to estimate the high scenario. However, the approach for the power generation sector is different, and the pathway mapping to our scenarios is inverted for Electric Engagement and Holistic Transition to provide consistent results.

The CCC’s Sixth Carbon Budget [177] is used to estimate the proportion of hydrogen demand that occurs in England and Wales for each sector as the FES results estimate demand for Great Britain as a whole. This process is carried out for both 2030 and 2045 periods for the low, central and high scenarios.

Table 28: Hydrogen regional demand split between England and Wales

The only sector that does not map directly between the Sixth Carbon Budget and FES 2024 is surface transport which includes rail in the Sixth Carbon Budget. The regional split for surface transport is assumed to apply to road transport for this analysis.

To estimate the hydrogen demand reduction from the announcement of the closure of Grangemouth refinery, in September 2024, Gemserv interpreted data and forecasts in NESO’s Future Energy Scenario’s databook [194]. The total demand provided by Grangemouth in each forecast were extracted and multiplied by an assumption on what proportion of this demand was forecasted as being served by hydrogen. This proportion was assumed to follow the forecasted mix between fuels of oil, hydrogen and gas for total Industry and Commercial sector.

Table 33: Grangemouth refinery hydrogen demand adjustment.

Aviation

The UK has announced its intentions for a SAF mandate which increases the proportion of SAF in the aviation fuel mix, this policy also includes a PtL sub mandate [186]. For this obligation to be met, PtL derived fuels must meet 0.5% of aviation fuel consumption in 2030, rising to 3.5% by 2040. The PtL sub mandate increases by 0.4% points for the five years between 2036 and 2040 [187]. For the purposes of this analysis, it is assumed that this trajectory continues and the PtL sub mandate increases to 5.5% by 2045.

Total aviation demand for the UK in the years 2030 and 2045 is based on the CCC’s Sixth Carbon Budget, utilising the Widespread Innovation and Tailwinds scenarios as these are the highest and lowest demand scenarios for aviation fuel. The central scenario is estimated as the midpoint between these. To estimate SAF demand in England and Wales, the regional split from the Balanced Pathway annual SAF demand is applied. England and Wales are estimated to be responsible for 94% and 93% of UK demand respectively for the years 2030 and 2045.

International Maritime

The UK generally does not report on energy consumption in the international maritime sector; however, T&E have developed analysis that estimates over 7 million tonnes of fossil marine fuel oils are used in the total maritime sector [184]. For the purposes of this analysis this is assumed to be exactly 7 million tonnes. The energy content of this fuel is estimated using EU Commission assumption of 40.5 MJ/kg for Marine Gas Oil (MGO) [188]. It is assumed that international maritime makes up 80% of fuel consumption based on the emissions estimates produced by T&E. Major port freight activity is used to estimate the proportion that occurs in England and Wales, estimated to be 81% of the UK total [189]. The proportional change in total energy demand for shipping is assumed to be the same for England and Wales and the assumptions made for the EU as a whole.

Once estimates of fuel demand in 2030 and 2045 are estimated, the proportion of this that is met with hydrogen derivates is applied to estimate derivative demand in the two time periods. The analysis assumes that the UK achieves less in terms of e-fuel deployment than the EU by 2030 due to its less ambitious policy in the sector. However, the UK Government has recognised a requirement to have at least 1% low-carbon shipping fuels by 2030. The analysis assumes that this is entirely met by e-fuels for the high scenario, half met by e-fuels for the central scenario and entirely met by other options such as biofuels for the low scenario. Due to the low technology readiness of ammonia as a shipping fuel, it is assumed that the 2030 demand is met with e-methanol. This is also in line with DNV data on fuel choices for ships on order, where 8% are methanol powered on gross tonnage basis [190]. For 2045 the assumptions for England and Wales follow that of the rest of the EU reflecting the international nature of shipping refuelling requirements.

1. Additional Tables and Graphs for Projected Demand

Figure 17: Mix of different sectors and derivatives in all three scenarios for the years 2030 and 2045

Note: Industrial demand figure is an aggregate of hydrogen, ammonia and methanol demand, with road transport figure showing 100% hydrogen demand. Heat notes domestic heating demand only.

Figure 18: Demand scenarios for the EU for all three scenarios

Figure 19: Hydrogen demand scenarios for 2030 for all the regions

Figure 20: Hydrogen demand scenarios for 2045 for all the regions

Summary: Hydrogen Delivery Method

Summary: Industrial Feedstock

Summary: High-Temperature Heat

Summary: Transport

Summary: Power Generation

1. Stakeholder Engagement Approach

We interviewed stakeholders for one hour, following a semi-structured format. Interviews began by presenting the scope of the project and gathering high level thoughts on the storage technologies considered as well as identifying any potential gaps in scope. Questions were structured around the seven evaluation criteria in the scope of the project. The topics focused on in interviews are shown with the list of stakeholders below.

List of stakeholders

• Enquest
• Net Zero Technology Centre
• Centrica
• Hydrogen Europe
• Air Products
• DNV
• Johnson Matthey
• INEOS
• Scottish Futures Trust

Broad topics

• Which hydrogen derivates are likely to dominate the market?
• Which industries/ sectors are likely to be the main offtakers for HDPs?
• Which countries or regions would you consider main import/ demand hubs?
• What are some of the policy gaps and bottlenecks for hydrogen projects?
• What are the most likely end users for hydrogen products?

Key findings

• Most stakeholders suggest ammonia to dominate the European market. Some stakeholders also mentioned SAF (in addition to ammonia), green methanol and green diesels.
• There are several concerns about policy gaps and bottleneck too. Concerns include but are not limited to: concerns about subsidising export, absence of trade policies with other EU nations, lack of uniform approach to global carbon pricing, planning and permitting issues causing complexity.
• Stakeholders also mentioned some security concerns associated with ammonia like toxicity and difficulty in detecting leaks.
• Stakeholders expect Southern and Northern Europe to be the new major hubs for hydrogen demand.
• The most likely end-use sectors for hydrogen are fertilisers, shipping and aviation.
• Finally, the stakeholders also identified some Scotland specific challenges. Scotland will have to compete with both nearby regions like the EU and faraway regions like the middle east, north America and even Australia.

1. Table of units

References

Acknowledgements

The delivery team extends thanks to Dr Jamie Speirs, Reader and Deputy Director in the Centre for Energy Policy at Strathclyde University, and Dr Edward Brightman, Lecturer at the University of Strathclyde, for their thorough review and helpful and constructive comments throughout the project. Special thanks go to Dr Nicola Dunn, Project Manager at ClimateXChange, for her continuous support and valuable guidance. We also express our appreciation to the Steering Group for their insightful input and feedback and to the industry stakeholders who contributed to our research, providing essential perspectives.

We would also like to recognise the dedication and hard work of the Gemserv team, including analysts and graphic designers Rachael Quintin-Baxendale, Sandile Mtetwa, Dhairya Nagpal, Isaac Guy, and Thomas Gayton, whose efforts were key in bringing this report to its final form.

How to cite this publication:

Csernik-Tihn, S., Mitchell, J., Wilson, J., Morton, H. (2025) Review of demand for hydrogen derivatives and products’, ClimateXChange. DOI http://dx.doi.org/10.7488/era/5798

© The University of Edinburgh, 2025
Prepared by Gemserv 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 research completion, no legal responsibility is accepted for any errors, omissions or misleading statements. The views expressed represent those of the author(s), and do not necessarily represent those of the host institutions or funders.

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

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1. 
   

   Distance of less than 2,000 kilometres. ↑

   
   
2. 
   

   Distance of more than 2,000 kilometres. ↑

   
   
3. 
   

   Industry includes chemicals and petrochemicals, construction, food, beverages and tobacco, iron and steel, machinery, textile and leather, non-metallic minerals, non-ferrous metals, oil and natural gas extraction, paper, pulp and printing, refineries, and transport equipment. ↑

   
   
4. 
   

   These demand projections have been revised down to account for the closure of the Grangemouth refinery, announced in September 2024. The demand for the refinery as per NESO’s FES scenarios [194] was reversed, with assumptions according to data availability. The exact methodology used is discussed in Appendix E. ↑

   
   

Decarbonisation of domestic heating systems is crucial for achieving the Scottish Government’s ambitious climate change targets of net zero emissions by 2045. The transition to clean heating (e.g., heat pumps, district heating) will require changes to the Scottish housing stock, including preparing it to operate at lower flow temperatures than the current majority of 70-80°C. Flow temperature is the temperature a wet heating system warms water to before sending it to radiators in different areas of a building.

This study summarises the current evidence for flow temperature reduction in hot water (wet) systems and considers how this might be applied to the Scottish housing stock. Suitability is defined as a dwelling’s ability to reach thermal comfort for a range of external temperature test criteria. The researchers assessed the suitability of the present housing stock at present and with two different cost levels of retrofit.

Findings

Most of the Scottish housing stock is currently unsuitable for flow temperature reduction to 55°C or below on a winter peak day. However, many dwellings in Scotland could reach suitability for 55°C flow temperatures after the inclusion of retrofit(s). Effective retrofit measures include efficiency measures such as wall and/or loft insulation, upgrading radiators or a combination of smaller efficiency measures such as hot water tank insulation, draughtproofing and reduced infiltration measures.

In the higher cost retrofit scenario, 76% of homes become suitable for a flow temperature of 55°C on a winter peak day. This could prepare the housing stock to be ready for zero direct emissions systems without requiring gas boilers to be removed from homes immediately.

The research found that 30% of the overall housing stock is unsuitable for a flow temperature below 75°C, and 20% require a flow temperature above 75°C. This suggests these dwellings are either running at temperatures higher than 75°C or are currently unable to reach thermal comfort during periods of peak demand.

Fuel bill savings from reducing flow temperature are significant and range from £151m to £501m in the stringent external temperature test cases. The associated greenhouse gas emission savings are estimated to be 6.17–10.18 MtCO2 equivalent per year, depending on external temperature cases and retrofit scenarios. Exploring the potential for varying flow temperatures throughout the year could be one way to increase savings.

The most important factor when assessing suitability for flow temperature reduction is in setting temperature criteria that captures the needs of occupants. The research used stringent criteria in the assessments, requiring a dwelling to be heated to 20°C during the coldest hour of an average or 20-year winter peak. It was selected to ensure the heating needs of the most vulnerable households were considered. This may not reflect the reality of how heating systems should be expected to perform.

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

Research completed: February 2023

DOI: http://dx.doi.org/10.7488/era/3385

Executive summary

Background

Decarbonisation of domestic heating systems is crucial for achieving the Scottish Government’s ambitious climate change targets of net zero emissions by 2045. The transition to zero direct emissions heating systems (e.g., heat pumps, district heating) will require a suite of changes to the Scottish housing stock, including preparing it to operate at lower flow temperatures than the current majority of 70-80°C. Flow temperature is the temperature a wet heating system warms water to before sending it to radiators in different areas of a building.

This study summarises the current evidence for flow temperature reduction in hot water (wet) systems and considers how this might be applied to the Scottish housing stock. Suitability is defined as a dwelling’s ability to reach thermal comfort for a range of external temperature test criteria. We assess the suitability of the present housing stock as it is today and then with two different cost levels of retrofit. The assessment method includes a literature review, stakeholder interviews and scenario modelling to test different temperature cases.

Findings

We have found that most of the Scottish housing stock is currently unsuitable for flow temperature reduction to 55°C or below on a winter peak day (see Figure 1).

Many dwellings in Scotland could reach suitability for 55°C flow temperatures after the inclusion of retrofit(s). Effective retrofit measures include efficiency measures such as wall and/or loft insulation, upgrading radiators or a combination of smaller efficiency measures such as hot water tank insulation, draughtproofing and reduced infiltration measures.

In our higher cost retrofit scenario, 76% of homes become suitable for a flow temperature of 55°C on a winter peak day (see Figure 2). This could prepare the housing stock to be ready for zero direct emissions systems without requiring gas boilers to be removed from homes immediately.

Figure 1 Absolute number of dwellings suitable to meet thermal comfort at each flow temperature (°C) on a winter peak day with no retrofits

Figure 2 Absolute number of dwellings suitable at each flow temperature (°C) on a winter peak day with more extensive, higher cost, retrofits

We find that 30% of the overall housing stock is unsuitable for a flow temperature below 75°C, and 20% require a flow temperature above 75°C. This suggests these dwellings are either running at temperatures higher than 75°C or are currently unable to reach thermal comfort during periods of peak demand.

Fuel bill savings and emissions reduction from reducing flow temperature is significant and range from £151m to £501m in the stringent external temperature test cases. The associated greenhouse gas emission savings are estimated to be 6.17–10.18 MtCO₂ equivalent per year, depending on external temperature cases and retrofit scenarios. Exploring the potential for varying flow temperatures throughout the year could be one way to increase savings.

The most important factor when assessing suitability for flow temperature reduction is in setting temperature criteria that captures the needs of occupants. We used particularly stringent criteria in our assessments, requiring a dwelling to be heated to 20°C during the coldest hour of an average or 20-year winter peak. This may not reflect the reality of how heating systems should be, or are currently, expected to perform but it was selected to ensure the heating needs of the most vulnerable households were considered.

Technical Glossary

Introduction

Domestic heating system decarbonisation is crucial for achieving the Scottish Government’s ambitious climate change targets of 75%, 90% and net zero emissions, relative to 1990, by 2030, 2040 and 2045 respectively. The transition to zero direct emissions heating (ZDEH) systems will require changes to the Scottish housing stock. This will potentially including preparing the building stock to operate at the lower flow temperatures that ZDEH options such as heat pumps operate.

Currently, the majority (approximately 85%) of dwellings in Scotland are heated by water based (wet) boiler systems, which typically operate at flow temperatures between 70-80°C. The remaining dwellings are heated by a mix of communal, heat pump, electric and off-grid systems. Flow temperature reduction has the benefit of reducing the energy required to meet the same internal room temperature, thus leading to reduced emissions and fuel bill costs in gas boiler and ZDEH systems alike.

We summarise the current evidence base for reducing flow temperature in the existing housing stock. We consider how flow temperature reduction might be applied to Scottish housing by modelling a range of lower flow temperature and assessing the potential suitability with varying degrees of retrofits.

Findings from literature review and stakeholder interviews

Range of temperatures for consideration

Evidence base for 55°C

According to the Heat Pump Association (see Appendix 8.1), 55°C is considered the “target” temperature for transitioning existing residential heating systems to lower-flow temperature systems. This is because it is an effective and relatively feasible “middle ground” between flow temperatures of current residential gas boiler currently (>70°C) and the direction of travel towards ZDEH technologies such as heat pumps (which operate optimally between 30-55°C).

At 55°C, most condensing boilers will run more efficiently (because more latent heat can be transferred from the flue gases at lower return temperatures) and there will be a reduction of wear and tear caused by cycling at current flow temperatures. Heat pumps, on the other hand, will reach the limits of their peak efficiency at approximately 55°C; at higher flow temperatures, efficiency will drop below quoted performance.

We found wide agreement in the stakeholder interviews (see Appendix 8.1 for stakeholder engagement overview) that most homes in the UK, and most homes in Scotland, will be able to run heating systems at 55°C without significant retrofitting. According to the CCC (2022), based on a report conducted by Nesta and Cambridge Architectural Research (2022), approximately 27% of homes in the UK currently are suitable for flow temperature reduction based on assumed ancillary attributes (namely radiator and pipework suitability). It is our understanding that a property assessment was not undertaken as part of the Nesta/Cambridge work. This estimate is about half of that found in previous research (Element Energy, 2021), which found that 53% of the UK stock was able to run at 55°C on a typical winter day (the percentage is reduced to 10% to reach thermal comfort on a winter peak day).

It was the opinion of our interviewed stakeholders that most homes in Scotland can successfully be run at 55°C, and that there were few attributes that would rule out this flow temperature (see Appendix 8.4).

Potential for further reduction

It is difficult to transition the housing stock to even lower flow temperatures below 55°C. The proportion of homes which are suitable without any works (or without major works) is significantly lower. Stakeholders suggested that some homes may not be suitable at all, but it is unclear if there was any tangible evidence or guidelines this was based on.

Our previous work (Element Energy, 2021) showed that the percentage of stock suitable for reduced flow temperatures reduces from 53% to 25% at 50°C, 6% at 45°C and <1% at 40°C. On a winter peak day (with an assumed external temperature almost 10°C lower) these proportions of houses suitable reduce to 3% at 50°C, 1% at 45°C and <1% at 40°C.

At lower flow temperatures, the specific heat loss of a property becomes increasingly important. Specific heat loss, in practice, is an indicator of how much heat will be required to maintain thermal comfort. Heat loss tends to have an inverse relationship with efficiency – a home with a low specific heat loss rate will be highly efficient, while homes with a high heat loss rate tend to be less efficient.

This is an important consideration when assessing the suitability of reducing flow temperature because in a home without retrofitting, a reduced flow temperature will decrease the amount of heat delivered to a room. If a room is difficult to heat because the home has a high heat loss rate, it becomes increasingly difficult to reach the desired temperature of that room because the system cannot adequately deliver or retain heat.

In this situation, one or both of the following paths can be taken to make a home suitable for a lower flow temperature:

Increase delivered heat. To do this, specific components of the heat system may need to be replaced or adjusted. The two key components are pipework, which impacts the flow rate of water through the system; and radiators, which emit heat transferred from the water. Existing pipework may need to be replaced to allow for a higher flow rate (which would help move more heat through the radiator in a given time period). Radiators could be replaced with larger units, which will allow more heat to be emitted due to an increase in absolute surface area. One or both options will increase delivered heat.

Decrease specific heat loss. To do this, a home needs to become more efficient through retrofitting to increase efficiency and airtightness. The two most important retrofits that can be undertaken are insulation (loft or wall) and window glazing. In addition, draughtproofing can be applied to windows and doors. These measures will lead to a higher rate of heat retention, meaning the absolute amount of heat that needs to be transferred to reach thermal comfort in a home is decreased.

Building envelope measures to increase suitability for flow temperature reduction

Increasing the efficiency of the building envelope decreases specific heat loss, thus supporting flow temperature reduction. Stakeholder interviews emphasised the importance of home retrofitting and maintenance, especially where homes are poorly insulated, as it also leads to heat demand reduction.

Home insulation

In general, more insulated homes will be more suitable for lower flow temperatures, due to the lower heat demand to reach thermal comfort. It is unlikely that there is a situation in which a home is “too insulated”, except if this insulation does not allow for moisture to be driven from the masonry.

Interviewed stakeholders considered insulation as one of the most influential aspects for suitability to operate at lower flow temperatures. Despite a general concern that traditionally built homes were unlikely to be suitable for a lower flow temperature, one stakeholder suggested loft and wall insulation is likely to be sufficient. It makes little difference if the loft is used as a room (CCC, 2022), as insulating in either case will decrease the home’s heat loss, but additional care should be taken due to the likely increased cost.

Window glazing

Similar to insulation, improving window glazing to double glazing or secondary glazing, is always beneficial for increasing the suitability of homes for reduced flow temperatures because they reduce the specific heat loss of a property. While triple glazing may offer benefits, it can introduce ventilation concerns and results in a lower marginal efficiency gain for flow rates compared to the adoption of double glazing.

Both double glazing and secondary glazing can effectively lower heat loss, but double glazing is a more expensive process and involves replacing entire units. Replacing existing windows with double glazed windows may be more difficult or restricted in traditional homes due to conservation/listed building status or for aesthetic reasons. Care should also be taken to balance ventilation requirements with increased glazing.

Ancillary components for the reduction of flow temperature

Ancillary components are key to effectively increasing delivered heat and/or decreasing specific heat loss. The overall efficiency of the heating system and, more generally, home energy efficiency will increase the suitability for flow temperature reduction. Some ancillary components are particularly important to a home’s suitability, and these are discussed in the following sections.

Radiators

When radiators are fitted, the size of radiator suitable for a home is determined with consideration to the flow temperature the heating system runs at, alongside flow rate, to determine an adequate size to meet thermal comfort. If all else remains constant but the flow temperature is reduced, it is possible that the heat transferred to the radiator will not be sufficient. To mitigate this, existing radiators can be replaced with larger units which can transfer more heat, but this may be more expensive than other retrofit measures.

Pipework

Pipework is likely to be a key attribute for suitability of a home to increase the flow rate of the heating system. Like radiators, piping tends to be sized for the heating distribution system. Pipework may need to be replaced to account for a lower flow temperature, but our previous work (Element Energy, 2021) and stakeholders consulted had mixed opinions as to whether increased flow rate was an effective counterbalance to reduced flow temperature, and whether it would be required.

During our engagement with Renewable Heat (see Appendix 8.1, it was suggested homes were built or had heating system replacements between the 1980s and 2002 are more likely to require pipework replacements. During this period, a copper shortage led to smaller piping instalments across the industry. Due to an update to buildings regulations in 2002 this is not an issue for newer builds.

Pipework, compared to other ancillary components, is particularly susceptible to maintenance problems leading to inefficiencies. For example, past analysis (Element Energy, 2021) found that efficiency reductions due to sludge (15%), hydraulic imbalance (10%), air (6%) and limescale (15%) can impact the ability for a heating system to reach thermal comfort.

Other considerations

The efficiency improvements possible for pipework highlight the importance of regular maintenance for heating systems. Heat distribution systems should have annual maintenance servicing, but our recent analysis (Element Energy, 2021) found that currently only 20% currently participate in this. Proper maintenance would increase overall system efficiency, thus making reaching thermal comfort at lower flow temperatures more feasible.

Key risks to reducing flow temperature

Thermal comfort (human and fabric)

Reaching adequate thermal comfort is the goal of assessing the feasibility of lowered flow temperatures. There are clear guidelines (British Gas, 2022) set by knowledgeable bodies (including the Lullaby Trust, Energy Savings Trust, World Health Organisation and Age UK) for temperatures homes should be heated to depending on the occupant, including:

• Homes with new-borns should be heated between 16–20°C
• Homes with healthy occupants should be heated to 18°C
• Homes with occupants which are old, young or unwell should be heated to 20–21°C (some recommendations state homes can be warmed to 18°C as long as the main living space of the older occupant is heated to 21°C)

In practice, there are many instances where these temperature thresholds are not met, for technical and behavioural reasons. This complicates suitability assessments, because setting the above thresholds may require heating systems to perform to temperatures that are not used in practice. Some behavioural reasons homes are not heated to the above thresholds may include:

• Turning heating on/off in bursts, instead of maintaining a constant temperature
• Regularly keeping heating at a comfortable temperature below the guideline temperature (for example, 18°C instead of 21°C)
• Refraining from heating despite discomfort (often associated with fuel poverty)

The disconnect between recommended thermal comfort and behavioural practice makes assigning a temperature threshold for lowered flow temperature complex, but previous reports and stakeholders generally agree a reasonably lower flow temperature will not cost consumers’ thermal comfort. It should be noted that special care may need to be taken for identified vulnerable consumers.

Nesta and The University of Salford (2022) suggests lower flow temperatures may lead to longer warming times, if flow rate and radiator size are not changed at the same time, due to the decrease in transferable heat. The acceptability of increased warming times would likely require a behavioural study.

Reduced flow temperature could also mean that room temperature cannot reach thermal comfort guidelines. It is not clear by how much and if this would cause a reduction from current practice. In the Nesta and The University of Salford (2022) study, homes with boilers and reduced flow temperature were able to reach within 0.5–2°C of thermal comfort (set at 21 °C in the living room, 22°C in the bathroom and 18°C in all other zones) on an average heating day, which is likely to be sufficient for most homes with healthy consumers.

Similarly, reduced flow temperature may make reaching thermal comfort on peak heating days more difficult. Further testing is likely to be required to better understand the impact of heating during periods of lower external temperatures. It could be the case that systems with reduced flow temperatures are within 2°C of thermal comfort on these peak days, which may be acceptable to occupants, but this is masked by the binary threshold of reaching thermal comfort.

Stakeholders agreed that buildings generally do not suffer from damp, moisture, and mould when the home is heated to human thermal comfort levels. Ensuring thermal comfort for humans is likely to provide adequate heating and avoid impacts on the building structure as well.

Unsuitable ancillary components

In many homes, reducing flow temperature without also retrofitting (e.g., adding insulation, replacing pipework, upgrading radiators) may cause the system to under-perform. The home would not reach thermal comfort due to the reduction of transferable heat and unimproved specific heat loss or system efficiency. Conversely, if the heating system is replaced before the home is retrofitted (insulation and window glazing, for example) the heating emitter could be oversized, causing increased cycling or inefficiency. To ensure this is not the case, retrofitting measures should be implemented before or in tandem with reducing flow temperature for an individual property.

Concerning the building masonry, the level of energy efficiency retrofitting should be balanced against the need to ventilate the home properly and drive moisture out of the walls to avoid deterioration of the home’s exterior. This is a particular concern in older dwellings but should be considered for all dwellings. One stakeholder suggested approximately 100mm of wall insulation would be a good balance, but previous analysis suggests this may not be adequate insulation for energy efficiency. More research may be needed to understand this balance better.

Costs incurred by significantly lower temperatures

The Heat Pump Association suggests homes which are not properly retrofitted to increase heat delivery or decrease specific heat loss could be required to heat their homes for significantly longer periods of time, and thus higher overall energy consumption. This, in turn, would lead to an increase in both energy usage and the absolute value of energy bills.

Our engagement with the Heat Pump Association suggested that lower temperatures will require increasingly airtight, well-insulated homes with larger radiators to ensure the heat loss doesn’t rise above 150W/m². For most homes, a flow temperature reduction to 45°C should not incur significant financial costs. To reduce flow temperatures further, homes must be increasingly efficient and airtight, potentially with larger radiators. These costs are likely to be prohibitive for many without financial support.

Key benefits to reducing flow temperature

Energy savings

When combined with required retrofits, reducing flow temperatures is expected to reduce energy use significantly. Previous work suggests savings are roughly correlated to the degree of change between the baseline temperature and new flow temperature. There are continued savings to be achieved by lowering flow temperature below 55°C.

Nesta and the University of Salford (2022) found 16–23% energy savings in gas used for heating when flow temperatures as low as 48.2°C were tested. This correlates to roughly 12–17% of overall gas savings at household level (assuming heating accounts for 75% of gas use in residential buildings). At low flow temperatures, care must be taken to ensure a boiler’s intended operating regime is maintained, for example maintaining efficiency of a condensing boiler.

These energy savings will lead to savings in in fuel bill costs at the household level, due to the lowered energy required to heat the distribution system. The level of fuel bill savings will depend on a combination of flow temperature and fuel prices.

Emissions savings will also be a result of flow temperature reduction. Most homes in Scotland are heated with natural gas, so the direct reduction in natural gas use will reduce emissions. For homes heated with electricity, reducing electricity use on a grid that is not completely zero carbon will have indirect emissions reductions.

ZDEH readiness

The Salford Energy House (2022) study shows that even homes using boilers can benefit from reduced flow temperatures. The retrofits and system upgrades required for such a switch are often “no regret” decisions, no matter what future heat source the home will use (whether it be natural gas, hydrogen, electricity or district heating) because these changes improve the overall efficiency of the homes.

In general, low carbon heating systems run on lower temperatures, so all ancillary works, maintenance and upgrades will smooth the transition to a low carbon heating system across all home archetypes. There was agreement amongst stakeholders that ancillary works and reducing flow temperatures prepare houses for ZDEH systems. Systems with lower flow temperatures (including those currently using gas) use less overall energy to meet demand because the whole home system is more efficient.

Methodology for assessing flow temperature reduction

Overview

This study seeks to model the suitability for potential flow temperature reduction in heating systems in Scottish homes. The ideal methodology for an assessment of flow temperature reduction potential would include a property-specific heat loss calculation. In lieu of this, our method uses heat demand and property characteristics as a proxy for current ability to meet demand.

Property characteristics including levels of insulation, current heat distribution systems and heat demand was provided by the Home Analytics Scotland (HAS, 2022) dataset. The HAS dataset provides characteristics of the Scottish housing stock based on a compilation of datasets and modelling. This dataset is the result of whole-stock modelling conducted by the Energy Saving Trust. It should be noted that there is a discrepancy between the number of properties modelled as part of the work in this report (2,747,067 dwellings) and data in the Scottish House Condition Survey (Scottish Government, 2021) which accounts for approximately 10% less homes. We believe this is due to the modelling method used by Home Analytics Scotland.

Our assessment of suitability was led by stakeholder interviews and previous work (Element Energy 2020b, 2021). The previous work developed a suitability assessment for the UK housing stock based on dwellings’ current oversizing factor.

Retrofit options were modelled using prices for materials and labour for individual retrofits taken from previous work for the CCC (Element Energy, 2020a).

Results from suitability modelling were then translated into energy demand reduction using heat demand profiles from the National Energy Efficiency Data-Framework (NEED), Scottish weather data and heat system efficiencies. Cost and emissions savings were calculated using up-to-date fuel prices and emissions data from recent Element Energy analysis.

Modelling approach

Defining suitability

The first step in this study’s methodology was defining suitability, which considered both internal temperature and external temperature. Both sets of temperatures were based on previous work commissioned by BEIS (Element Energy, 2021).

The target internal temperature was 20°C, which is the lower end of the World Health Organisation’s (WHO) recommended internal temperature range for dwellings with vulnerable occupants. While not every home has vulnerable occupants, there is no robust way to predict what homes will be occupied by vulnerable consumers, and as such an internal temperature target was chosen which could meet the needs of any consumer at any hour of a given year. This temperature is also aligned with the Microgeneration Installation Standard (MIS) 3005 (MCS, 2019), which recommends living zones maintain a temperature of 18–22°C.

We tested a dwelling’s ability to reach thermal comfort (20°C) at various external temperature cases:

• Winter peak, our central case which tests suitability during the peak heating hour of an average year.
• 20-year peak, which tested a dwelling’s ability to reach thermal comfort during the peak heating hour of a historic cold snap. Also referred to as a historic cold snap.
• Winter average, which tested a dwelling’s ability to reach thermal comfort during an average heating hour in an average winter (as opposed to the peak heating hour in the winter peak).
• November average, which tested a dwelling’s ability to reach thermal comfort during an average heating hour in an average “shoulder season” (the heating hour used in this study is taken from an average November).

Suitability at a set internal and external temperature test case was measured based on the dwelling’s oversizing factor, which is the ratio of peak radiator capacity to peak demand. See Appendix 8.2 for more information on why oversizing factors were used in lieu of specific external temperatures. Based on this oversizing factor, we know what minimum flow temperature each dwelling can operate at and still meet thermal demand. Oversizing factor ranges are set out in the BEIS study (Element Energy, 2021). Oversizing factors of between 1.00 and 1.20 suggest a dwelling’s radiator capacity is adequately sized for the dwelling, while an oversizing factor under 1.00 suggests a heat distribution system will not be able to reach thermal comfort and a factor of over 1.20 suggests a heat distribution system is larger than required for the dwelling at a given flow temperature.

Archetyping and radiator mapping

The housing stock was aggregated into seven archetypes with the aim of modelling the suitability and impact of flow temperature reduction for a set of “average” homes. These archetypes were primarily based on stakeholder insights on the key determinates of flow temperature reduction based on their experience (age and house type). These were compared to the archetype design of the BEIS study, which used similar archetypes. The seven archetypes were:

• Pre – 1919 flats (approximately 10% of stock)
• Pre – 1919 houses (approximately 7%)
• 1919 – 2002 flats (approximately 23%)
• 1919 – 1949 houses (approximately 6%)
• 1950 – 1983 houses (approximately 27%)
• 1984 – 2002 houses (approximately 10%)
• Post – 2002 dwellings (flats and houses) (approximately 14%)

All dwellings in the HAS database were assigned an archetype, which was used for energy demand reduction, fuel bill and emissions savings calculations. We then assigned oversizing factors. Extrapolation of BEIS (Element Energy, 2021) survey data to the entire UK housing stock provided a distribution pattern across archetypes. This was used to assign oversizing factors for Scottish dwellings across the archetypes. Dwellings surveyed in the BEIS study were assigned archetypes from the above list and reassigned a proportion of the archetype stock that they represented based on extrapolation from the original study which maintained the robustness of the original study’s housing stock mapping.

The clearest relationship observed in this data was that between building footprint and radiator capacity, with larger dwellings tending to have larger capacities. Dwellings in the BEIS survey and HAS dataset were ordered by archetype and building footprint. The radiator size, building peak demand and oversizing factors were assigned to dwellings from smallest to largest building footprint, maintaining the correct proportions in the housing stock. For example, if the smallest surveyed home in the pre-1919 flats archetype was found to represent 2.7% of the stock, this dwelling’s data was assigned to the smallest 2.7% of HAS dwellings in the same archetype, and so on. This allowed the data to maintain the same oversizing factor distribution.

Suitability modelling

The suitability of the current housing stock portfolio was modelled based on the minimum flow temperatures each HAS dwelling could operate at using the oversizing factor. Retrofit packages were assigned to dwellings based on their archetype and existing levels of insulation. Two retrofit scenarios were modelled:

• The Lower cost retrofit scenario, where retrofit package costs could total approximately £2000 per dwelling, and
• The Higher cost retrofit scenario, where retrofit package costs could total up to 10% of the cost of a whole-home renovation. To determine this cost, the average price of a whole home renovation was taken for an “average” home, which was then scaled up or down for each archetype. This led to a range of costs between £6,000 – £12,000 (see Table 1 for these costs).

Table 1 Retrofit costs for dwellings in the Higher cost retrofit scenario, by dwelling type

Dwellings were assigned retrofit packages based on the specific dwelling attributes in the HAS dataset. Because these attributes are in the original dataset, retrofit packages were assigned regardless of what external temperature case or radiator sensitivity was being tested.

Each dwelling was assigned two packages, one for each retrofit scenario (see Appendix 8.3 for list of retrofits). In both scenarios, most homes are assigned standard energy efficiency measures and/or radiator upgrades (75% and 71% in the Lower and Higher cost retrofit scenarios, respectively, see Figure 3 below). For many dwellings, additional insulation measures are required based on current level of insulation modelled by HAS. In some of these cases, dwellings can be insulated within the approximately £2000 price bracket, while other homes are more expensive to insulate. In these situations, the cost to insulate falls within the more expensive retrofit scenario.

Retrofit packages took a fabric first approach, prioritising measures with higher efficiency gains (mostly wall and loft insulation), then measures with lower-efficiency gains (increased draughtproofing, reduced infiltration measures and hot water tank insulation) and finally radiator upgrades where applicable. See Appendix 8.3 for details.

After a retrofit package was assigned to all dwellings in each retrofit scenario, the efficiency increases are applied to the dwellings assigned oversizing factors. This study assumed a direct relationship between energy efficiency increases and demand reduction, so an efficiency increase of 18% was applied by reducing the oversizing factors by 18%. These new oversizing factors were used to reassign dwellings to minimum flow temperatures. In practice, this may not reflect how efficiency increases are observed in dwellings, but an implementation-based study would be required to accurately capture this.

Fuel bill and emissions modelling

Results were aggregated at archetype level and used to find archetype-level energy demand reduction for fuel bill and emissions savings modelling. To calculate energy demand reduction at the archetype level, the average energy demand was calculated from the NEED (BEIS, 2022). Hourly energy demand profiles were calculated using the Watson method (Watson et al., 2019). We assumed all dwellings currently operate at 75°C flow temperature. The difference between 75°C flow temperature and lower temperatures (down to 50°C) was calculated based on the proportion of the stock which could support this for different external temperature case and retrofit scenarios. All dwellings suitable at temperatures below 50°C were modelled using 50°C savings, due to uncertainty over some boiler’s efficiency at lower temperatures. The cost and emissions modelling outputs were expected to be conservative estimates for fuel bill and emissions savings, due to not capturing the potential savings from 85°C to 75°C and temperatures under 50°C.

To calculate fuel bill savings, two fuel prices (representing a historic average and more recent fuel costs) were used to give a range of savings based on the energy demand reduction on national, archetype and archetypal individual dwelling levels.

To calculate emissions savings, the average natural gas emissions in Scotland were applied to the energy demand reduction on national, archetype and archetypal individual dwelling levels. In this calculation, all dwellings were modelled as gas boilers due to the overwhelming majority of boilers in the breakdown of heat distribution systems in the Scottish housing stock. Only 15% of homes do not currently use gas boiler systems, instead running on electricity or off-grid heating systems. Due to higher price per kWh for electricity, we expect these modelled results to be conservative estimates.

Method limitations

This study sets out to model flow temperature reduction suitability, for which practical research has not been conducted previously on Scottish housing stock. Our study aggregated several data sources and relied on previous research to assess suitability in lieu of property-by-property heat loss calculations and real time case studies for retrofitting and monitoring. As such, the method has several limitations that should be acknowledged when considering findings and conclusions (see Table 2 below for an overview of these limitations).

Table 2 Summary of method limitations and key assumptions with rationale and impact

Modelling results

Overview

We find that the majority of Scottish housing stock is currently unsuitable for flow temperature reduction to 55°C or below on a winter peak heating hour. However, more than half (60%) of the stock is suitable for a flow temperature reduction during the less stringent test case using the winter average. Both retrofit scenarios considered increase suitability for flow temperature reduction across all external temperature cases and home types. With Higher cost retrofits, between 64% (winter peak) and 97% (November average) of homes become suitable for a flow temperature of 55°C or below.