Low carbon heat technologies
The call for evidence considered the wide range of current and potential future technologies that could have a role to play in decarbonising heat in off-gas buildings. This included varying forms of low carbon electric heating, biomass and bio-liquid, heat networks and gas grid extension. This section considers evidence in relation to each of these technologies in turn, and on further opportunities for innovation in low carbon heat.
Readers should note that respondents’ focus on specific low carbon heat technologies appeared to reflect their experience and expertise. For example, those active in a particular energy sector typically focused on associated technologies. As such, views expressed on specific technologies cannot necessarily be read as representative of the full range of opinion. References are provided for specific claims where possible, and we note where evidence was not provided. Statements of opinion provided without evidence may not have been included.
Common themes and issues for low carbon technologies
While some responses were relatively narrow in their focus on specific low carbon technologies, a range of common themes and issues were raised by respondents. These reflected the core of call for evidence questions asked in relation to each technology - on cost, consumer satisfaction, lifecycle and efficiency, and barriers to uptake. However, some of the themes noted below were also evident in responses to later questions on enabling uptake and growing the supply chain for low carbon heat, and earlier questions on the current market (see previous section).
Cost was a prominent theme in responses across all low carbon technologies, and was seen by some as a key barrier to uptake. This included suggestions that installation and/or running costs are a particular barrier to uptake of heat pumps, electric storage heating and heat networks, and some cited evidence on the relative installation and running costs for specific technologies.
Other common cost-related issues suggested by respondents included:
- Respondents suggested that capital and running costs vary significantly between installations, and are sensitive to factors such as building energy efficiency, heating system design and location (typically higher in more remote and island locations, in part due to the limited local supply chain).
- Respondents saw some scope for costs to reduce as the supply chain matures, competition increases, and new low carbon technologies develop. However, some suggested there is more limited scope for reduction in the capital cost of mature technologies such as heat pumps.
- Some raised concerns around the accuracy of performance and cost estimates for a range of low carbon technologies, including heat pumps and biomass heating. Examples were cited where real world operation of low carbon systems had failed to meet predictions. Respondents suggested that predicting energy performance for specific buildings is difficult. MCS guidance was cited as advising against making definitive predictions of energy performance, but it was suggested that some installers do not comply with this. As a result, consumers may not see the predicted cost savings and financial ‘payback’ can take significantly longer than expected. One public sector respondent suggested there was a need for independent research on the running costs of biomass heating.
- Some suggested that current fuel taxation disadvantages electrical heating, including low carbon technologies such as heat pumps.
Respondents were asked for evidence on the lifecycle and efficiency of each low carbon heat technology, and a range of specific estimates were provided. These supported a broad view that lifecycles are longest for GSHP, electric storage heaters and biomass heating. Respondents expressed a range of views on the relative efficiency of low carbon heat technologies, including some citing specific evidence. Some respondents suggested that performance of low carbon heating can be highly dependent on factors such as building energy efficiency and heating system design. Some also felt that there is a limited evidence base on the ‘real world’ lifecycle and efficiency of low carbon heat, in part due to the relatively small install base for some technologies. Respondents saw a need for further research to provide definitive estimates of performance across a range of circumstances.
Relatively little specific evidence was cited on customer satisfaction with low carbon heat. Again respondents suggested that this in part reflected the limited install base for some technologies. Some also suggested that customer satisfaction, and the wider reputation, of specific technologies is highly sensitive to factors such as heat performance and running costs. In this context, some suggested that cost savings are a key motivation for a large proportion of consumers when replacing a heating system. The risk (noted above) of consumers being provided with exaggerated performance estimates for low carbon heat was seen as an important factor in ‘bad press’ around specific technologies such as heat pumps. Some also suggested that consumers required better information and training to ensure they use new technologies efficiently.
A number of common barriers to uptake of low carbon heat were raised by respondents, although some were described as more significant barriers for specific technologies. Many of these barriers reflected issues raised earlier at Questions 3 and 6, including a focus on costs and financing, supply chain, and consumer awareness. The main barriers suggested by respondents were:
- High installation cost relative to ‘traditional’ systems was seen as the most significant barrier for a range of technologies including heat pumps, hybrid heating systems, bioenergy and heat networks. Respondents cited survey feedback indicating that installation cost is a key reason for households delaying or choosing not to install renewable energy heating systems. This included potential for installation costs to be significantly higher for retrofit of low carbon heat, dependent on design of the existing heating system and any requirement for energy efficiency improvements. Running costs were seen as a less significant barrier to uptake of low carbon heat, although some cited evidence of low carbon installations leading to increased running costs. Running costs were seen as a potential barrier to deployment of electric storage heating.
- A range of respondents suggested that the low carbon heat supply chain is limited in some areas, particular rural locations and islands, and saw this as a barrier to uptake. Some suggested that this contributed to higher installation costs for low carbon heat. Supply chain limitations were also seen as having a negative impact on the quality of advice provided to consumers, resulting in more consumers choosing like-for-like replacements.
- Consumer awareness and satisfaction were regarded as potential barriers to uptake of low carbon heat. Some cited evidence indicating that only a small proportion of consumers are aware of specific technologies. There was a perceived need for better access to high quality information and advice for consumers.
- Disruption associated with a change to low carbon heat system was also suggested as a barrier for consumers. This including some suggesting a ‘hassle factor’ where consumers are required to learn how to manage a new type of heating system. Some respondents also suggested that consumer may be affected by fears around changing to a new technology that many will not have seen in-situ. Potential for disruption was regarded as a particular issue for ‘distress’ purchases to replace a failed system. Respondents cited evidence that a large proportion of heating system replacements are made in these circumstances; that 7 in 10 heating system changes are ‘distress’ replacements, and that only 1 in 10 consumers would consider replacement while their heating system was still working. These were seen as a factor in consumers’ disinclination to choose a new form of heating.
- The built form of off-gas buildings was mentioned by some, including suggestions that low carbon heat can be unsuitable for some building types. This was in terms of the economic viability of installation costs, likely performance and running costs. Some also regarded internal and external space requirements as a potential barrier to deployment. This included internal space required for thermal storage and biomass systems, and external space for ground source heat pumps and biomass storage.
- Some respondents suggested that electricity network capacity could be a barrier to large scale deployment of electrical low carbon heating, including reference to air source and ground source heat pumps (ASHP and GSHP). Network capacity was seen as a particular issue for off-gas buildings in rural and island locations.
Respondents suggested a broad range of approaches to overcome barriers to deployment of low carbon technologies. Some suggestions were specific to individual technologies, but most were applicable across multiple technologies. Reflecting the key barriers noted above, suggestions were typically focused around policy and regulation, financial support, supply chain development, and consumer awareness and acceptance.
A range of respondents saw a need for stable, long-term policy to provide certainty for industry and to allow time to build consumer awareness and acceptance. This was a particular concern for private sector respondents. Respondents recommended a range of specific regulatory or policy changes, some reflecting issues discussed in the previous section in relation to the current market for low carbon heat:
- A firm end-date for installation of high carbon heating systems (suggestions in the range 2020 to 2035), and a subsequent firm target date for conversion of existing off-gas high carbon heating systems to low carbon heat.
- Building regulations to require installation of low carbon heat to new build development and major renovations, or ‘future proofing’ of new development to ensure suitability for subsequent of low carbon heat.
- Revision to the EPC framework to place greater emphasis on carbon emissions, and reduce the influence of fuel costs.
- A requirement for installers of ‘traditional’ heating systems to include low carbon options when quoting for heating system replacement, and to signpost consumers to independent advice on low carbon heat.
- Use of zoning through LHEES to create ‘zero carbon’ areas, and communicating this to consumers through Energy Efficient Scotland assessments and local engagement schemes.
- Making the decarbonisation of heat a National Infrastructure Priority.
- Adapting the UK Government’s Boiler Plus policy to Scotland.
- Establishing a publicly-owned National Energy Service to coordinate activities to increase uptake of low carbon heat.
- A clear policy statement on the role of bioenergy as a means of diversifying approaches to decarbonising heat.
There was a view across respondent types that financial support continues to be necessary to overcome cost barriers, reflecting perceptions that installation cost is a key barrier for consumers. Some suggested that the need for public finance could reduce as the supply chain develops and capital costs reduce. However, there was a common view that funding would be required beyond 2021. Respondents made the following recommendations for approaches to financial support:
- Larger upfront payments to overcome installation cost barriers, particularly for lower income households and those in fuel poverty.
- Provision of and/or encouraging development of low and zero interest financial products, including long-term loans and green mortgages. Some suggested that the renewables loan scheme had seen some success. A role was suggested for the proposed Scottish National Investment Bank.
- Incentives for energy efficiency improvements to make low carbon heat a feasible option for more off-gas buildings.
- A boiler scrappage scheme.
- Removal of public finance for installation of high carbon heating.
- Increase in upper limits to available funding for larger non-domestic systems.
- Government-sponsored mass purchase schemes to reduce costs.
- Energy pricing and tariffs were suggested as a means of incentivising uptake of low carbon heat. This included reform of fuel taxation to penalise high carbon fossil fuels, and encouraging further development of time of use tariffs.
- Tax relief on electricity bills and reduced Council Tax and/or business rates for buildings with low carbon heat. Some also suggested retention of reduced VAT for solar PV, and application of the reduced rate to district heating.
Respondents also suggested a need for further development of the supply chain for low carbon heat, including improved skills and understanding and expanding capacity across Scotland. Some suggested that a more stable policy framework would encourage this development. Specific suggestions included an installer skills development programme to build on current training and education opportunities, incentives for installer skills development including new entrants to the sector, and a focus on building capacity to provide advice to consumers.
Some respondents perceived a lack of consumer awareness around the scale of changes required to achieve Government targets, and the need for urgent action. These respondents wished to see work to build on existing networks and initiatives to improve consumer awareness and understanding. Specific suggestions included:
- Sharing of case studies and more positive messages around low carbon heat options.
- A role for the media in raising awareness of the need for urgent transition to low carbon heat.
- Targeting of ‘trigger points’ such as house moves and major renovations to encourage uptake of low carbon heat, and key groups such as first time buyers to raise awareness of potential for low carbon heat to lower emissions.
- Use of Energy Efficient Scotland assessments and energy advisors to raise consumer awareness of low carbon heat.
Some also saw a need for better quality advice for consumers to address gaps in consumer understanding, improve confidence and reinforce the potential role of low carbon heat. This included suggestions for in-person energy advice targeted at ‘trigger points’, more up to date information and case studies, and greater promotion of national advice and referral mechanisms. The Green Homes Network was recommended as a potential vehicle for improving consumer awareness and acceptance of hybrid systems. Extended warranty and maintenance contracts were suggested to improve consumer confidence.
Respondents citing electricity grid constraints as a barrier to uptake recommended a number of approaches to address this. These included linking to local renewable electricity generation and more use of storage, smart controls and other demand side management, including as a data source to more accurately assess how to manage energy demand.
The call for evidence paper asked for evidence relating to a range of electric heat technologies including electric heat pumps, hybrid heat pumps and storage heaters. In relation to each technology, evidence was sought on cost (and how these compare to RHI costs quoted in the call for evidence paper), customer satisfaction and efficiency. Respondents were also asked for evidence on potential barriers to uptake of each technology and how these may be addressed.
Electric heat pumps
Questions 9 to 12 sought evidence on electric heat pumps including ground source, air source and water source technologies. Heat pumps typically provide heat at lower temperatures than conventional heat sources and as such can have specific requirements in terms of heating systems (e.g. larger heat emitters or underfloor heating) and heating patterns (e.g. on for longer to achieve comfortable temperatures).
A total of 27 respondents (50%) addressed one or more parts of Question 9.
Comments regarding the capital and installation costs of heat pumps are summarised below.
- Capital expenditure costs for heat pump systems were seen as higher than direct replacement of existing systems, including quotes of 3-5 times the installation costs for a boiler replacement.
- Some suggested that RHI capital expenditure costs for domestic and non-domestic heat pump systems are in line with experience for ASHP and GSHP, although GSHP costs are sensitive to ground collector loop design. Examples of systems where costs differ somewhat from RHI were also cited.
- Capital costs were suggested to be sensitive to the complexity and location of individual projects, and typically higher in more remote and island locations. For example, evidence was cited indicating that GSHP systems on the islands are typically more than £2,000 per kW due to additional transport and overhead costs. Installation costs for a range of non-domestic heat pump installations on an island authority were quoted; air source heat pump costs were broadly in line with RHI costs, but GSHP costs varied significantly (in part linked to varying system capacity).
- Some suggested there is limited scope for equipment costs to fall as heat pumps are a mature technology, but saw potential for significant reduction in installation and administration costs as installer numbers and skills increase. It was estimated that there is potential for a 30-35% reduction in overall capital costs.
- An ‘other organisation’ suggested that replacement costs for some ASHPs have increased significantly in recent years.
- Some suggested that capital expenditure costs can be recouped over a period within a heat pump’s lifetime by reduced energy and maintenance costs.
Comments regarding running and maintenance costs of heat pumps are summarised below.
- Some cited evidence that heat pump performance compares favourably with existing systems, including significantly lower running costs than LPG boilers. Respondents cited a range of specific cost examples. This included a public sector respondent citing ASHP costs as being higher than those set out in the call for evidence paper, and significant variation in GSHP costs. However, some suggested that even with higher installation costs, heat pumps can still be a more affordable and significantly lower carbon system. Others suggested that energy costs can vary significantly between installations.
- A public sector respondent reported that running and maintenance/service costs can be significantly higher than those cited in the call for evidence paper. An ‘other organisation’ is conducting research to collate heat pump maintenance cost data, which could be made available once completed.
- Respondents also noted the range of servicing and maintenance services offered by heat pump suppliers.
Some raised concerns around the accuracy of performance and cost estimates for heat pumps, noting that SCOP methodologies can exaggerate performance. Respondents noted that the MCS Heat Pump Working Group is looking to identify a more accurate methodology for performance estimates.
Some suggested that RHI cost tables were too simplistic due to the number of variables that can influence installation and running costs, and suggested that cost comparison does not take account of varying lifespan of different technologies. For example, a private sector (heat pump) respondent suggested that GSHP units typically have a somewhat longer lifespan than ASHP, and the ground collector element a lifespan in excess of 100 years.
A range of respondents referred to positive satisfaction ratings from consumers, including specific case studies and feedback from consumers. One private sector (renewables/low carbon) respondent suggested that customer satisfaction is lower for GSHP.
Customer satisfaction was described as highly sensitive to factors such as building energy efficiency, heat distribution and emitter design, and control design. Consumer understanding was also suggested as an important driver of satisfaction. Negative customer feedback included reference to systems being difficult to use and respondents saw high quality training in use of heat pump systems as important in addressing this. Some also suggested that customer dissatisfaction can reflect inappropriate heat pump specification and poor installation.
Lifecycle and efficiency
Some respondents suggested there is a robust evidence base on typical lifecycles of ASHP and GSHP. Specific estimates ranged between 15 and 30 years, with some suggesting longer lifecycles for GSHP. This was compared favourably with lifecycle of ‘traditional’ systems including gas boilers.
Some respondents commented positively on the efficiency of heat pumps, although others were less positive. It was suggested that a more robust evidence base is required. Some respondents cited estimated efficiency coefficients, although again views were mixed. Some referred to efficiency ratings of 3-4 and up to 5, dependent on specification and building energy efficiency, while others were concerned that an unacceptable proportion of heat pumps fail to achieve minimum Seasonal Performance Factor (SPF) performance of 2.5. It was also suggested that GSHP can show stronger performance than ASHP.
Barriers to uptake
A total of 35 respondents (65%) addressed Question 10, and 32 (59%) addressed Question 11.
Factors inhibiting uptake of heat pumps reflected some of the common themes discussed earlier in this section. These included costs, disruption to consumers, building type, supply chain capacity, and consumer awareness and confidence.
High installation cost, and particularly retrofit cost, was the most commonly suggested factor inhibiting uptake. Cost of energy efficiency improvements required for efficient heat pump performance was also suggested as adding significantly to installation costs. Respondents suggested that a long period can be required to recoup installation costs through lower running costs, and in some cases the cost is unlikely to be recovered.
Higher than anticipated running costs were also suggested by a range of respondents, including cases of running costs being higher than existing systems. Some referred to examples of ASHP being less efficient than expected, and less efficient than GSHP. Other issues regarding running costs included suggestions that maintenance costs can be a barrier for consumers and can be higher than ‘traditional’ boilers.
Disruption to consumers was also seen as a barrier. This included the need for replacement of heat emitters, and installation of ground loops for GSHP.
Respondents referred to a range of building types and circumstances where heat pumps were regarded as less suitable. These included properties with poorer energy efficiency, heating systems designed for high temperature heat (for example with smaller heat emitters), and properties lacking external space for infrastructure such as ground collectors or condenser units, and internal space for water tanks.
A range of respondents suggested there is a lack of customer awareness of heat pumps, citing evidence that only a quarter to a third of consumers are aware of heat pump technologies. This included specific reference to unfamiliarity with how heat pumps are installed and operated, and a lack of training/education to support consumers in adapting to an unfamiliar technology.
Evidence was cited of customer feedback that heat pump performance does not meet expectations, and in some cases does not represent sufficient improvement on existing systems to be worthwhile. Examples of poor performance included poor efficiency and inadequate heat performance during winter, frost build-up for small heat exchangers, noise and poor aesthetics, and concern about lifespan in a marine climate. Some workshop participants also suggested that limitations in the supply chain can also undermine consumer confidence.
Recommendations to overcome barriers to uptake reflected the common themes discussed earlier in this section, including policy and regulation, financial support, supply chain capacity and consumer understanding. Recommendations specific to heat pumps are summarised below.
Specific regulation and policy changes advocated by respondents included a requirement for smart heating and remote monitoring as part of all heat pump installations. In addition to benefits in managing heat demand, it was suggested that this can also provide valuable evidence on system performance and help to support development of the ‘heat as a service’ sector.
Respondents saw a continuing need for financial support for heat pumps. This included a perceived need for more upfront financial support at the design and feasibility testing stage for non-domestic projects, and finance tailored to specific technologies including short-term loans for heat pump units, and longer-term finance to support installation of GSHP infrastructure.
Innovations to reduce costs
A total of 22 respondents (41%) addressed Question 12.
Comments on potential innovations to reduce operational costs of heat pumps focused around several areas including specific pump technologies, the role of solar PV and energy storage in demand management, energy tariffs, and new business models.
Current and emerging heat pump technologies were suggested as having potential to reduce operational costs. Specific reference was made to:
- Improving co-efficiency of performance via appropriate design and sizing of heat pump systems.
- Use of high temperature heat pumps able to work with existing wet space heating systems.
- Development of frost-free air source heat pumps.
- Wider adoption of smart controls to manage heat demand and maximise efficiency of heat pumps.
- Use of remote monitoring to minimise maintenance costs, particularly in areas with a limited installer base..
- Energy recovery via cooling.
- Use of innovative systems to improve the efficiency of wet heating systems.
A range of respondents supported use of solar PV with a heat pump system, incorporation of thermal storage to reduce the size of plant required, and use of smart controls and smart networks to manage demand and reduce costs. Respondents suggested that storage costs are relatively high at present, but suggested there is considerable scope for further development of the UK market to reduce costs.
Some suggested time of use and other tariffs as a means of reducing costs for consumers and maximising carbon savings. Positive comment included the potential to combine time of use tariffs with thermal or electric storage and solar PV, and reference to the benefit of smart controls to manage demand. Other comments around the potential role of time of use tariffs included potential benefits for consumers with electric vehicles as a means of optimising power flows, and scope for tariffs to reward consumers using heat pumps.
There was also some support for wider adoption of ‘Heat as a Service’ models, potentially integrated with time of use tariffs, with some seeing potential to change consumer behaviour. However, a private sector respondent suggested there is little evidence to support claims around the potential benefits of service models for heating appliances.
Hybrid heat pumps
Questions 13 to 16 sought evidence on hybrid heat pump technologies. Hybrid systems combine a heat pump to meet baseload demand, alongside an existing fossil fuel boiler or other heat source to meet peak demand.
A total of 25 respondents (46%) addressed one or more parts of Question 13.
Comments regarding the capital and installation costs of hybrid heat pumps are summarised below.
- Some respondents suggested that hybrid heat pump systems have lower capital costs than electric heat pumps, including reference to a study commissioned by Department for Business, Energy & Industrial Strategy (BEIS). Respondents linked reduced costs to factors including the ability to specify a smaller heat pump unit and reduced ground collector loop (for GSHP). A reduced need for disruptive retrofit was seen as a significant contributor to cost savings, including avoiding replacement of heat emitters and reducing the need for electricity network upgrades. As such, savings were seen as most significant for retrofit rather than new build installation.
- Some suggested that the economic viability of heat pumps can be sensitive to capital costs, and that hybrid heat pumps can improve the economic case by enabling installation of a smaller heat pump with lower capital cost.
- A small number of respondents cited specific capital costs for hybrid heat pump systems, indicating savings of 20-25% compared to standalone electric heat pumps. Some suggested that lifecycle costs of hybrid heat pumps remained higher than other options such as gas boilers and high-efficiency boilers using BioLPG, primarily due to higher capital costs.
Comments regarding running and maintenance costs of hybrid heat pumps are summarised below.
- Some respondents suggested that hybrid heat pump systems could deliver reduced running costs relative to alternatives. This included potential efficiency and running cost savings relative to standalone electric heat pumps.
- However, it was suggested that the extent of any savings was dependent on the type of system being replaced. For example, respondents noted that the FREEDOM project in Wales found significant savings for LPG boiler/heat pump hybrids when compared with standalone LPG boilers, but that gas boiler/heat pump hybrids did not produce savings over an efficient standalone gas boiler. It was also suggested that running cost savings are dependent on correct setup and use of control systems.
- A public sector respondent suggested that non-domestic hybrid heat pump systems can increase maintenance and servicing costs, for example where systems incorporate multiple heat pump and boilers.
Some raised concerns around the evidence base on hybrid heat pumps. This included reference to the limited number of installations to date and the complexity of comparing various forms of hybrid system with the range of alternative technologies. Some noted that the FREEDOM Project was currently the only UK field trial of hybrid heat pumps, and suggested that the trial had not provided a definitive conclusion on the relative performance and costs of hybrid systems.
Some private sector respondents also suggested that hybrid systems will need adaptation or replacement over the longer-term to achieve decarbonisation. There were concerns that use of hybrids should not delay deployment of currently available fully low carbon systems.
Respondents cited some examples of positive customer satisfaction relating to hybrid heat pumps. These included non-domestic (in the agricultural sector) and domestic systems, and heat sources including GSHP, oil-fired and solid fuel systems. Respondents also suggested that design of hybrid heat pump systems and consumer understanding of their operation are also important factors for customer satisfaction.
Responses did not include specific evidence of customer dissatisfaction relating to hybrid heat pump systems. However, some suggested there is a limited pool of evidence on hybrid heat pump systems, including specifically for ASHP/natural gas systems.
Lifecycle and efficiency
Some respondents suggested there is a lack of evidence on the lifecycle of hybrid heat pumps, although others suggested that lifecycles of the heat pump element would be similar to that of standalone heat pumps. It was also suggested that lifecycle can depend on type of property (including energy efficiency) and customer energy needs.
In terms of efficiency, some drew favourable comparison with standalone heat pumps, suggesting that hybrid heat pumps can deliver better efficiency in some homes. This was linked to the heat pump meeting a more consistent load and using periods of lower cost electricity, while peaks are met by the secondary heat source. Respondents suggested that hybrid systems can benefit homes with high heat demand and/or poorer energy efficiency. However, it was also suggested that hybrid systems may not offer an advantage relative to heat pumps integrated with thermal storage.
Reducing peak demand and carbon emissions
In relation to reducing demand, respondents suggested there are circumstances where hybrid systems can deliver efficiency improvements and reduce impact on the electricity network through reducing the size of heat pump required. A private sector (renewables/low carbon) respondent described this as a ‘relatively straightforward way’ to improve efficiency and reduce peak demand. It was also suggested that hybrid systems can reduce electricity demand during times of grid constraints by switching to the supplementary heat source. However, others suggested that greater reliance on electrical heating, including through hybrid systems, would present more challenges for the management of peak demand during cold periods.
Regarding carbon emissions, respondents suggested that emissions reduction targets will require adaptation or replacement of hybrid systems in the longer term. This included a potential need for replacement with decarbonised alternatives, or adaptation to use zero carbon fuel. Some suggested that fuels such as bioLPG or bio-liquids are available now and could enable hybrid systems to deliver further carbon savings. However, others suggested that carbon emissions associated with the supplementary heating source undermined the benefit of hybrid heat pump systems.
Some also felt that further research is required to assess the potential efficiency and energy demand benefits of hybrid heat pumps relative to available alternatives.
Barriers to uptake
A total of 26 respondents (48%) addressed Question 14, and 24 (44%) addressed Question 15.
Factors inhibiting uptake of hybrid heat pumps focused on several key issues, reflecting some of the common themes discussed earlier in this section. These included installation and running costs, disruption to consumers, supply chain capacity, and consumer awareness and confidence.
High installation costs, and the relatively long return on investment required, was the most commonly suggested barrier to uptake. Other commentary around installation costs included:
- Suggestions that installation costs can be lower than for standalone heat pumps, in part due to hybrid systems reducing or avoiding costs associated with energy efficiency improvements. However, others suggested that capital costs can be higher where installation of both the heat pump and supplementary system is required.
- Costs associated with assessing feasibility and design of hybrid heat pump systems were seen as a barrier to uptake for non-domestic buildings.
Some suggested that running, maintenance and future replacement costs could also be a barrier to uptake of hybrid systems. This included suggestions that maintenance and future replacement costs can be higher due to a requirement to service two appliances. While some suggested that running costs for hybrid systems can be lower than standalone heat pumps in some circumstances, others raised concerns that running costs may be higher than predicted.
Comments around potential disruption associated with hybrid heating systems included the ‘complexity’ of hybrid systems using multiple fuel sources, and evidence of consumers typically preferring a like-for-like heating system replacement. Respondents also suggested that the small install base means there is limited evidence on consumer acceptance of hybrid heat pump systems.
Building type was seen as less of a barrier to uptake than was the case for standalone heat pumps, as the secondary heat source is able to meet the higher heat requirements of less energy efficiency buildings. However, some suggested that hybrid systems may be unsuitable for some property types due to space requirements.
Respondents suggested there is a more limited supply chain and install base for hybrid heat pumps. It was suggested that this could have a negative impact on the quality of advice for consumers, and potentially the quality of design and installation. Some suggested that consumers in some parts of Scotland could experience difficulty accessing maintenance and repairs.
Other views offered by respondents included a perception that limited policy and regulatory support for hybrid systems could limit uptake, and a perceived need to improve consumer awareness and acceptance of hybrid heat pump systems and to overcome ‘bad press’ associated with poorly designed installations.
Recommendations to overcome barriers to uptake of hybrid heat pumps reflected some of the common themes discussed earlier in this section, and those raised in relation to electric heat pumps at Questions 11.
Some felt that regulation is needed to drive the market for hybrid heat pumps, and to encourage private investment until these technologies are economically competitive. The most common suggestion for overcoming barriers to uptake was continuation and/or extension of public finance to meet capital costs. This included a specific suggestion of funding for feasibility testing and design for non-domestic hybrid systems. Energy pricing, including time of use tariffs, were also suggested as a means of incentivising uptake of hybrid heating systems. Some saw a role for remuneration for consumers when the hybrid systems are benefiting the network.
Buildings suitable for hybrid heat pumps
A total of 21 respondents (39%) addressed Question 16.
Respondents supported the call for evidence paper in emphasising the need for careful matching of heating technologies to specific building types. This included comments around the relative benefits and limitations of heat pump, hybrid and other technologies, although some suggested that build type is not a key criterion for deployment of hybrid heat pumps. Views on specific circumstances where hybrid heat pumps may be deployed are summarised below.
- Respondents suggested the following specific build types and usage as suitable for hybrid heat pumps:
- Non-domestic buildings including hotels, leisure centres, schools, offices, distribution centres and the agricultural sector.
- Communal living buildings such as sheltered housing and care homes.
- Buildings with high heat use throughout the year.
- Buildings of less than three storeys.
- Buildings with a relatively smooth heating profile and better energy efficiency standards, although it was suggested that hybrid systems may be suitable for properties where energy efficiency is insufficient for a standalone heat pump (or the necessary energy efficiency improvements are not feasible).
- Buildings with high temperature heating systems.
- Buildings in locations which typically experience less-severe winter conditions.
- Households that cannot afford the additional capital costs of a larger standalone heat pump or replacement of heat emitters.
Questions 17 to 19 sought evidence on electric storage heaters. Storage heaters store heat during periods of lower electricity demand (typically overnight) and then release heat when needed (typically during the day).
A total of 19 respondents (35%) addressed one or more parts of Question 17.
Respondents and workshop participants provided limited evidence on the cost of electric storage heating. This is summarised below.
- Some respondents suggested that installation costs for electric storage heating is typically lower than low carbon alternatives such as heat pumps and hybrid systems. Respondents cited some specific installation costs, with costs being higher for high heat retention storage heaters than older storage heating. It was also suggested that electricity network upgrades can add to installation costs.
- The high cost of electricity was suggested by respondents as contributing to high running costs for traditional storage heaters relative to alternatives. Newer technologies were described as having potential to reduce costs, with experience of 25% reduction for more efficient, fan-assisted and high heat retention storage heaters. Some wished to see more support for retrofit of more efficient storage heaters. However, others provided examples of upgrades failing to deliver the estimated level of fuel savings.
- Integration of smart controls was seen as having potential to further reduce running costs. Potential for integration of solar PV to offset running costs was also mentioned.
- Metering arrangements were also perceived as a potential issue for consumers; some suggested that these can be a barrier to switching from higher cost tariffs. It was also suggested that storage heating can be the only practical solution available in some remote locations.
- A small number of respondents provided estimates of maintenance costs for electric storage heating, suggesting that these are lower than for electric heat pumps.
Respondents also provided relatively little evidence on customer satisfaction with storage heating. Some suggested that electric storage heating has a poor reputation, with relatively low customer satisfaction in relation to traditional storage heaters. Evidence was also cited of customer satisfaction being lower than for gas heating.
Some respondents suggested that customer dissatisfaction was linked to high running costs and unresponsive heat performance (particularly in rural areas subject to harsh winters), and restrictions on switching fuel or supplier. Respondents cited examples of customer frustration around this issue being such that they chose to pay for storage heaters to be replaced with alternative systems.
Respondents also referred to examples of better customer satisfaction for newer, more efficient storage heating, including tenant feedback to social landlords. Respondents suggested that improved satisfaction related to better heat performance and efficiency, and to improved controls including integration with smart home technology.
Lifecycle and efficiency
Some respondents suggested that storage heaters are more efficient through use of cheaper off-peak energy. However, comments noted above regarding storage heaters being unresponsive and difficult to control were also suggested as contributing to poor efficiency. This included suggestions that a substantial proportion of households maintain a secondary heat source for later in the day when storage heaters are exhausted. Respondents suggested that modern high heat retention storage heaters can deliver significant improvements in efficiency compared to older storage heaters.
Although some respondents described electric storage heaters as being ‘unresponsive’ to consumer’s needs, others suggested that the technology is well-established, with good reliability and a relatively lengthy lifecycle. Respondents referred to examples of storage heaters in place for 25 years or more.
Barriers to uptake
A total of 22 respondents (41%) addressed Question 18, and 18 (33%) addressed Question 19.
Factors seen as inhibiting uptake of electric storage heating were focused around running costs, network capacity and poor customer satisfaction. These reflected some of the common themes discussed earlier in this section.
High running cost was the most commonly suggested barrier to uptake, including evidence indicating that storage heaters are higher cost than all other comparators. Running costs were suggested as a potential barrier in relation to poor efficiency of storage heaters and increasing electricity prices.
Other barriers to uptake of electric storage heating included:
- Respondents suggested that a requirement to upgrade domestic electricity systems can add to installation costs in some cases, but these were not seen as a significant barrier to uptake.
- Electric storage heaters were seen as having a poor reputation and poor customer satisfaction, sufficient to inhibit uptake. This included suggestions that customers have limited scope to switch supplier, that poor controls can lead to inefficient operation, that heat performance can be unresponsive, and that out of date or inconsistent consumer information fails to address concerns around cost and performance.
Some of those respondents raising issues for electric storage heating at Questions 17 and 18 did not see a significant role for the technology in decarbonising heat in Scotland. However, other respondents and workshop participants suggested that storage heating has the potential to make a contribution, including particular reference to flexibility in management of demand. A range of approaches were suggested as having potential to overcome barriers to uptake.
Reflecting the prominence of running costs as a perceived barrier to uptake, respondents felt there were a range of potential changes around electricity costs and tariffs to tackle running costs as a barrier to uptake of storage heating:
- More flexible tariff options could encourage consumers to consider more flexible systems such as storage heating. This included greater flexibility to change supplier, and improved access to time of use tariffs.
- Better publicity of the Competition and Markets Authority (CMA) Restricted Meters Remedy was also proposed, to improve understanding across consumers, support services and energy providers.
- Ongoing trials of smart grid solutions were seen as having potential to reduce electricity costs. This included projects integrating solar PV and battery storage (potentially in the form of storage heaters) to store electricity during periods of peak renewable generation, and release energy to meet peak demand.
- More support for electric storage heating through public funding mechanisms was also suggested.
Smart technology and controls were also seen as having potential to improve heat performance, reduce running costs and manage electrical demand at peak times. Some wished to see greater promotion of these options alongside storage heating.
Other electric heating sources and storage
Questions 20 to 23 sought evidence on other electric heating sources and the potential role of thermal or electric storage alongside electric heating systems.
A total of 11 respondents (20%) addressed Question 20, and 8 (15%) addressed Question 21.
Some respondents suggested that decarbonising heat in Scotland would require a diverse range of electric heating, and other heating sources. This included suggestions that some suitable technologies are on the market at present, and have received insufficient support from the Scottish Government. However, private sector and other organisation respondents also raised concerns around an approach that relied on converting large numbers of off-gas households to electric heating.
The following specific electric heating technologies were seen by respondents as having a role to play in decarbonising heat:
- Solar thermal heating and integration of solar PV and wind generation with heating technologies. This included an ‘other organisation’ respondent citing evidence of potential running cost savings for solar thermal panels.
- Use of battery storage, smart controls and time of use tariffs were seen as having potential to reduce running costs for storage or panel heaters, including for fuel poor households. Respondents referred to projects trialling use of smart electric storage heating.
- Electric boilers and electric combination radiators including solar PV-ready radiators. A private sector (renewables/low carbon) respondent cited findings from trials conducted by the Electric Heating Company and Delta-EE indicating that this technology has potential to deliver savings to installation, running and maintenance costs.
- Micro-CHP with electric battery and/or thermal storage, including potential for these systems to drive heat pumps in neighbouring properties.
- Infrared heaters used in solid wall buildings.
A total of 11 respondents (20%) addressed Question 22.
These respondents referred to a range of integrated systems incorporating heat pumps, solar PV, thermal and battery storage and other technologies. It was suggested that integrated systems typically have higher capital costs, but that well designed systems could deliver sufficient running cost savings.
Some expressed support for use of thermal or battery storage with heat pumps. An ‘other organisation’ respondent suggested potential for thermal storage and domestic heat batteries to deliver cost savings of up to 20%.
Some respondents also saw a role for solar PV integrated with storage and/or heat pumps. However, it was also suggested that there may be limited scope for battery storage to overcome mismatch between the generation pattern of solar PV (i.e. during summer) and peak heat demand.
A public sector respondent gave an example of an integrated wind turbine and heat pump system in Orkney. The system was described as ideally suited to an island location, with building energy loss due to wind speed being matched by increased energy and heat generation by the wind turbine.
A ‘Danish model’ of district heating was suggested as offering potential benefits in terms of efficiency and heat performance. This model involves integration of large scale solar thermal, biomass and inter-seasonal heat storage. It was suggested that the biomass component can be adapted to local fuel supply chains, or replaced with heat recovery. Evidence was cited of this model reducing connection costs, even in low density rural areas.
Overcoming grid constraints
A total of 16 respondents (30%) addressed Question 23.
Some were of the opinion that integrated systems can make best use of available energy infrastructure, and wished to see a ‘whole system approach’. Respondents suggested it will be important to manage peak electricity demand (during the day and inter-seasonally) if electrification is to play a significant role in decarbonising heat. However, there was also a suggestion that further work is needed to understand the potential role of different systems in balancing demand.
In terms of specific approaches to overcoming grid constraints, the following comments were made:
- Storage was seen as having an important role to play in managing demand and reducing impact on the electricity network at an individual building and larger network scale. Reference was made to thermal and electricity storage technologies, including existing projects using these technologies, although some suggested further work is required to understand the potential of storage.
- Respondents also saw a role for smart controls and demand side management, including as a data source to more accurately assess how to manage energy demand.
- The role of energy master planning and zoning was recommended by some.
- Other mechanisms and technologies seen as having a role to play in overcoming grid constraints included:
- Mechanisms such as Short term operating reserve (STOR), Capacity Market and Firm Frequency Response to address grid constraints.
- Conversion of excess renewable electricity to hydrogen for injection into the gas network.
- Electric heating as a dispatchable load.
- A range of local electricity and heat generation options including solar PV, wind and solid fuel.
In terms of market mechanisms to promote on site generation, some respondents recommended Ofgem’s Charging Review as a potential means of encouraging market mechanisms to promote on-site generation. Respondents also suggested specific market mechanisms as having potential to encourage on-site generation including time of use tariffs, smart pricing signals, and carbon taxes to encourage use of low carbon sources.
Biomass and bio-liquid solutions
Questions 24 to 29 sought evidence on bioenergy technologies including biomass and bio-liquid. Solid biomass can provide high temperature heat via conventional heat distribution systems, and currently accounts for more than 80% of renewable heat capacity in Scotland. However, there are concerns around the long term sustainability of domestic biomass feedstocks. The bio-liquid market and supply chains are less well developed, but bio-liquids can be used as a ‘drop-in’ fuel or like-for-like replacement in some circumstances and potentially offer an additional option for emission reduction in off gas buildings.
A total of 21 respondents (39%) addressed one or more parts of Question 24.
Some cited evidence that costs were broadly in line with those set out in the call for evidence paper, although it was suggested that costs can vary between projects. Modelled estimates were also provided, indicating that biomass heating systems are higher cost than alternatives. This included suggestions that costs quoted in the call for evidence paper somewhat under-estimate installation costs.
A number of private respondents, including LPG manufacturers or suppliers, suggested that bioLPG can be ‘dropped in’ to existing LPG systems with minimal installation or conversion costs, or new systems installed at a cost equivalent to conventional LPG heating. This was contrasted with bio-liquids requiring installation and supply chain investment, although a private sector respondent suggested that conversion to a 30% biofuel blend can be achieved at a reasonable cost without boiler replacement.
Respondents cited a range of evidence relating to running costs of bioenergy systems, including modelled estimated indicating that biomass systems are higher cost than heat pump and oil systems, and that cost savings can be achieved relative to LPG. Some suggested there is a price premium for bio-fuels, although it was also suggested that costs vary across fuels (for example evidence of lower costs per kWh for wood chip relative to wood pellet). A private sector (LPG) respondent suggested there is potential for fuel costs to decrease over time due to technological advances and market forces.
A number of private sector respondents referred to specific examples of projects or technologies. These included examples of bioenergy displacing oil and LPG in non-domestic buildings including care homes and hotels, and a suggestion that wood stoves can be a cost effective option for some homes but are not currently supported through the RHI.
Some respondents gave examples of positive customer feedback on biomass heating systems. Aspects of biomass heating systems seen as contributing to positive customer satisfaction included more stable fuel costs, reduced running costs, lower carbon emissions, reduced risk of theft, and no risk of leakage. Some public sector respondents suggested that customer satisfaction with biomass had been poor, including suggestions that this was linked to higher than expected fuel use and system faults or failures.
Lifecycle and efficiency
Respondents suggested that bioenergy technologies would have lifecycles similar to that of existing oil heating systems. Specific lifecycle estimates (provided by a number of primarily private sector respondents) ranged from 10 to 20 years. It was suggested that storage tanks can have lifecycles of up to 30 years.
Efficiency was described as varying dependent on factors such as boiler size, flue design, fuel specification and storage, control systems and maintenance. Some private respondents active in the biomass sector suggested modern biomass systems achieve very high efficiency levels in the A and A+ bands, while the efficiency of bioliquid systems was described as similar to that of current oil heating systems.
Types of feedstock
Respondents were of the view that locally sourced feedstocks should be used wherever possible to minimise carbon emissions and support local economies. Some suggested there is substantial feedstock capacity within Scotland, including views expressed by some active in the sector that wood pellet manufacture in Scotland is sufficient to meet local demand and for export across the UK and Europe. Some respondents saw a need to work with forestry, crop and other waste and residue processors to further develop local supply chains to maximise use of Scotland-based feedstocks, alongside use of imports where required. They suggested that this included potential to adapt use of feedstocks by specific projects to fit local supply, and suggestion of scope for use of moorlands to expand production of biomass feedstocks.
Respondents provided little evidence on the overall supply of feedstocks within Scotland. However, reference was made to a BEIS UK supply model estimating accessible UK feedstock supply for 2030. Dry fuels and wastes suitable for combustion or thermal treatment accounted for the largest proportion of this supply.
Respondents suggested that current bioenergy production across the UK makes use of a range of UK feedstocks, but only small quantities of dry crops, and also imported biofuels for transport and wood pellets for large-scale power production. It was suggested that there is scope to make fuller use of UK feedstocks through development of additional supplies and infrastructure, although some respondents suggested that some imported resources would still be required (such as wood pellets for large-scale power generation). Respondents suggested that a wider range of UK feedstocks were available, including:
- Dry feedstocks for combustion or thermal treatment such as agricultural residues, products from forestry and timber industries, perennial energy crops, wood waste, and renewable fractions of waste.
- Feedstocks suitable for production of biogas or biomethane such as food waste, sewage gas, slurry and landfill gas, livestock manures, and crops.
- Feedstocks for biofuels production such as bioethanol and biodiesel crops, and used cooking oil and tallow.
In terms of locally sources feedstocks, respondents commented as follows:
- Some suggested that wood pellets are more commonly used in Scotland than logs and wood chip (around 75-80% wood pellets), and that a large majority of the pellet supply is sourced within Scotland. Some also suggested there is a substantial local supply of wood chip feedstocks.
- Respondents suggested that supply of logs for stove heating included a mix of local supply and kiln dried logs imported from the UK and Europe.
- It was suggested that bioLPG is primarily produced as part of the refining process for bio-diesel, but that a range of alternative production methods are being developed. These included use of vegetable oils/animal fats, crops, animal waste and glycerine, although it was suggested that some sources required further development and were longer-term prospects. A private sector respondent noted that they had commissioned ongoing research on potential bioLPG feedstocks.
Barriers to uptake
A total of 22 respondents (41%) addressed Question 25, 21 (39%) addressed Question 26, and 11 (20%) addressed Question 27.
Factors seen as inhibiting uptake of bioenergy reflected the common themes discussed earlier in this section, such as costs, and policy and regulation. Respondents also suggested other barriers specific to bioenergy, such as emissions, air quality, supply chain and feedstocks.
Respondents suggested that high capital cost for bioenergy heating systems relative to fossil fuels, and long return on investment for consumers, could inhibit uptake. Some suggested that changes in RHI tariffs had a negative impact on biomass installations in recent years. Some also suggested that fluctuation in bioenergy fuel costs is a risk to consumers, and saw a need for sufficient economies of scale to be achieved to reduce costs. Maintenance costs were also suggested as a potential barrier.
Air quality concerns were seen as having restricted uptake of biomass heating, and for some were felt to reflect a lack of understanding of differences in performance and emissions across specific biomass fuel types. A public sector respondent also suggested that new regulations will restrict installations in urban areas, although others suggested that rural areas are the primary market for bioenergy.
A range of respondents felt that there is a limited supply chain for bioenergy at present. This was in terms of access to skills and expertise, and feedstocks (seen as a particular issue in some Scottish islands). The availability of a consistent supply of feedstocks for heating was seen as limiting consumer confidence and uptake of bioenergy heating. The allocation of a substantial proportion of feedstock supplies to transport and other streams was seen as a factor here. Some also perceived a lack of research and development funding required to develop new bioenergy fuels.
Some suggested a lack of policy and regulatory support for bioenergy had and could continue to limit uptake of the technology. Some respondents suggested there was potential for existing bioenergy markets to contract if financial support does not continue beyond 2021.
Recommendations to overcome barriers to uptake of bioenergy included some of the common themes discussed earlier in this section, and other approaches reflecting the bioenergy-specific barriers noted above. Suggestions focused on policy and regulation, financial support, supply chain development, and consumer awareness.
Respondents indicated their support for a clear, stable long-term policy framework to provide certainty for industry and consumers, and to encourage investment. This included comments from private sector respondents across the LPG, renewables/low carbon and other sectors. Respondents made the following recommendations for specific aspects of a policy and regulatory framework:
- Feedstock sustainability and quality requirements and greater recognition of the differing characteristics of specific types of bioenergy fuel.
- Consideration of opportunities for local waste sources to be converted to bioenergy supplies.
- Use of land reform to allow use of managed rural landscapes for bioenergy production.
- Linking bioenergy policy with Government commitments to expand forestry.
- A perceived need for a ‘Danish-style’ heat supply policy.
Continuing and increased financial support to overcome the barrier of capital costs was recommended by respondents across a range of respondent types. This included suggestions for grant plus loans for those unable to pay, and loans for self-funders.
Some public sector and private sector (renewables/low carbon) respondents supported further development of the bioenergy supply chain in Scotland, including diversification of feedstocks used for heat. This included a perceived need for support for expansion of readily available bioenergy technologies for building and industry heating, alongside development of medium to longer-term technologies including large-scale carbon capture. Some public sector respondents felt there was a need for incentives for additional training and skills development, and increased warranty and maintenance provision.
There was a perceived need across respondent types for improved consumer awareness and understanding of bioenergy, including the different characteristics of specific fuel sources and how these fit with different build types. Recommendations included more ‘case studies’ illustrating the potential role of bioenergy heat, and targeted promotion for key non-domestic sectors.
Potential for growth in biogas supply
Some private sector (LPG) respondents saw potential for clear Government policy to accelerate growth in the biogas market. This included reference to numbers of new biogas plants as indicative of the positive impact of changes to RHI tariffs. In this context, respondents made the following points:
- The Committee on Climate Change has recognised biogas as a ‘no regrets solution’ able to support reduction in carbon emissions with minimal infrastructure changes.
- Some saw scope to draw on successful deployment of biogas globally to support rapid growth in Scotland.
- A private sector (LPG) respondent suggested there were potential economic benefits associated with biogas, including localised production supporting local economies and potential for Scotland to become a net exporter of biogas.
A private sector (renewables/low carbon) respondent cited evidence that the bioenergy contribution to heating in the UK could be increased by a factor of 2.3 by 2032. Respondents who felt there was strong potential for growth in biogas supply suggested the following specific technologies and circumstances:
- Potential to increase supplies of bioLPG as a by-product of increased biodiesel production.
- Potential for gasification of sustainable feedstocks, such as residual household waste, to develop as new sources of low carbon gas.
- Potential for industries such as brewing and distilling as sources of biogas.
- Most discussed the role of bioLPG for off-gas buildings, but a private sector (renewables/low carbon) respondent suggested there is potential for biogas to supply domestic or non-domestic heat networks in rural areas.
Some suggested there is potential for feedstock demand from other technologies such as transport, to limit growth in bioenergy for heat. This was seen as a particular issue in the context of restrictions on land use, and a strategic approach was recommended to make best use of available feedstocks.
An individual respondent questioned the extent to which increasing use of biofuels would contribute to an overall reduction in carbon emissions, and was of the view that any savings would be outweighed by reduced absorption of CO2 by the bioenergy crop together with processing and transport emissions.
A total of 15 respondents (28%) addressed Question 28, and 12 (22%) addressed Question 29.
Respondents provided relatively little evidence on the relative cost of Scottish-produced bioenergy feedstocks, but provided a number of broader points in relation to the cost of biofuel relative to fossil fuels. These are summarised below.
- Respondents provided cost estimates indicating that biofuel is lower cost per kWh than heating oil and LPG.
- Some suggested there was scope for bioenergy feedstocks to replace fossil fuels with relatively low capital investment required. This included views that pressure jet burners can be converted to biofuel with relative ease (although it was suggested that not all burners are suitable for conversion), and that transport requirements can be met by existing infrastructure without significant investment.
- Some respondents cited evidence indicating that biomass feedstocks are higher cost than fossil fuels, including oil and gas.
- It was suggested that the diversity of bioenergy feedstocks contributed to significant variation in costs. This included a suggestion that locally produced feedstocks, and particularly waste product, had the potential to reduce costs. It was also suggested that there is a price premium for some ‘innovative’ feedstocks.
- Some regarded price volatility of biofuel as a risk to expansion of biofuel for heating in Scotland.
Responses on the potential for bioliquid fuels to be supplied sustainably at reasonable cost is summarised below.
- The sustainability of biofuels was regarded as a well-documented issue, and it was suggested that regulation had led to a move from raw material to waste feedstocks such as used cooking oils and fats, oils and greases.
- Some suggested that the most promising bioliquid options required further development to improve production and/or efficiencies.
- Some suggested that bioliquids have historically been higher cost than fossil fuel equivalents, but cited recent fuel price trends of this price differential closing as supply of biodiesel and Used Cooking Oil Methyl Ester (UCOME) has increased. It was suggested that market trends indicate the cost of bioliquids would reduce further as supply continues to grow.
- Some respondents were of the view that the level of ongoing research and development work around biofuels has proven the range of potential bioliquid fuels. The use of a diverse range of bioliquid fuels was seen as a more sustainable approach than reliance on a single or small number of fuels.
- A range of specific forms of bioliquid were regarded as having a potential role to play in decarbonising heat, including products being introduced in coming years. Specific bioliquids referenced by respondents included:
- Bioethanol and biodiesel crops.
- Bio-kerosene produced from waste plastics.
- Used cooking oils, tallow, and fats, oils and greases. This included specific reference to hydrated vegetable oil and production of biodiesel from used cooking oils.
- Gas-to-liquids derived from natural gas.
- Blends of kerosene with biodiesel or hydrated vegetable oil.
- Liquid fuel produced through synthesis using renewable electricity and carbon dioxide.
- Algae-based fuels.
Respondents suggested that locally produced feedstocks can minimise transport-related carbon emissions, and support local business and employment. Land available for feedstock production and competing demand from other sectors were regarded as limiting access to locally produced feedstocks, although it was suggested that transport demand could decline as uptake of electric vehicles increases. Some saw a need for the Scottish Government to take a strategic approach to feedstocks.
Some suggested that a significant proportion of off-gas buildings could be supplied by Scottish feedstocks. This included a private sector respondent indicating that their research estimated that bioliquids could meet the needs of all oil-heated homes if heat demand is reduced through energy efficiency improvements, although evidence was not provided in support of this.
Questions 30 to 34 sought evidence on heat networks. A heat network is a distribution system that takes heat from a central source to multiple properties via insulated pipes. Heat networks can be designed to use a wide range of heat sources including waste heat recovered from industry and urban infrastructure, sewers, canals and rivers, or waste plants as well as heat generated from different fuels including fossil and biofuels, or as part of a CHP system.
A total of 23 respondents (43%) addressed one or more parts of Question 30.
Installation cost was regarded by some as a barrier to deployment of heat networks. Few respondents cited specific cost data, but it was suggested that the density of heat demand was rarely sufficient to make a project economically viable without contribution from the developer, connection charges or public finance. Key points raised in relation to installation costs included:
- Some respondents suggested that a minimum housing density is required for a heat network to be economic. This included a suggestion of 50+ dwellings per hectare, although evidence was not provided in support of the suggestion. Some suggested specific heat network projects had been assessed as unviable due to high installation costs, insufficient heat demand and/or the high fuel tariffs required to recoup installation costs. This included public sector respondents who reported having been unable to make an economic case for heat networks.
- Others suggested there was potential for small scale heat networks that were economically viable. This included potential use of ‘anchor’ buildings such as leisure centres or hotels to supplement heat demand in off-peak months.
- Respondents provided cost estimates indicating the impact of length of pipework on overall installation costs, reinforcing the importance of building density for capital costs. It was also suggested that design of heat networks can reduce costs, for example it was suggested that use of waste heat to reduce the scale of heat source required can significantly reduce capital costs.
It was suggested that assessment of heat networks should be on the basis of full lifecycle costs, reflecting the importance of running costs to consumer charges. Reference was made to ongoing development of a compliance programme to ensure accountability for lifecycle costs through project phases.
Respondents cited a range of evidence on running costs for heat networks including case study examples, research evidence and modelled estimates. This included examples of running costs for low carbon heat networks being similar to or lower than existing heating systems. However, some suggested that running costs vary such that it is difficult to make meaningful comparisons. Factors such as cost of finance, ownership model, heat network design, maintenance and control systems, and energy tariffs were suggested as impacting on running costs.
It was suggested that linking consumer costs to a ‘counterfactual’ effectively sets an upper limit on potential income for heat networks, such that reducing capital costs provides the best opportunity to reduce the level of public funding required. Some saw a need for revised price setting criteria for heat networks.
Uncertainty around future heat costs to consumers was seen as a potential deterrent for individual heat users. Some also suggested that lengthy contracts required to recoup capital costs can prevent tariff switching.
Some suggested there was the potential for heat networks to have a positive local economic impact, and saw this as an important consideration in relation to cost. This included in terms of supporting employment and, if locally produced biomass is used, retaining fuel spend within the local economy.
Relatively few respondents cited evidence on customer satisfaction with heat networks, noting the limited scale of heat network deployment in Scotland. Some cited evidence that heat network users report satisfaction in line with that seen across other heating systems, including a BEIS survey of heat network customers and CMA market study. A Which? report on heat networks was cited as having found more varied satisfaction levels.
Respondents cited these sources, and other examples of heat networks in Scotland, as highlighting a range of factors impacting customer satisfaction. These included system reliability, perceived fairness of price, information provided on the system, and handling of complaints. Charging and billing issues were also suggested as impacting customer satisfaction, including frustration for dissatisfied customers unable to switch supplier.
Lifecycle and efficiency
Respondents cited a range of evidence relating to the lifecycle and efficiency of heat networks, although some suggested that the evidence base is limited by the small number of well-established examples.
Specific lifecycle estimates ranged from 20-25 years to 50+ years. The latter estimate was provided with reference to DECC research, although it was suggested that assets with moving parts have a shorter lifecycle. Some suggested that lifecycle of heat networks should be broadly similar to individual low carbon units, although it was also suggested that lifecycles can vary between heat networks. For example, longer lifecycles were suggested for lower temperature heat networks such as ambient loop systems.
Respondents referred to research evidence and experience in suggesting that efficiency of heat networks is affected by a range of factors. These included modelling of demand and system design, use of heat recovery, and the length and type of pipework to minimise heat loss. Some saw a need for standards to ensure heat networks meet minimum performance and efficiency levels, including for temperature range, pressure controls and annual performance reporting. Data collection was suggested as a means of increasing heat network efficiency.
Barriers to uptake
A total of 32 respondents (59%) addressed Question 31, and 29 (54%) addressed Question 32.
Respondents suggested a range of factors that may inhibit installation of heat networks. These included some common themes discussed earlier in this section such as cost and a limited supply chain, and other barriers more specific to heat networks such as ‘demand risk’ and the built environment.
High capital expenditure was suggested as a key factor across respondent types. This included reference to infrastructure costs, additional costs where sites have insufficient density of demand, planning application fees, cost of negotiating commercial contracts and property agreements. High capital costs were regarded as contributing to very long payback periods. Respondents also suggested there were difficulties accessing funding, particularly for smaller networks in rural areas, and that developers were unwilling to bear additional costs.
‘Demand risk’ was regarded as a key factor limiting installation of heat networks, where uncertainty around the number of consumers likely to connect to a network can undermine the economic case. This was described as a potential ‘catch-22’ where consumers do not wish to agree a contract prior to the heat network being installed, but the installation cannot go ahead until sufficient contracts are in place. Other suggested barriers related to demand risk and running costs of heat networks included:
- Low heat consumption in new build development due to improved energy efficiency, and the risk of low heat demand in off-peak months.
- Higher running costs relative to high carbon alternatives, particularly where higher tariffs are required to recoup capital expenditure. It was also suggested that heat network consumers are subject to higher rates of VAT on energy.
- The resources and expertise required by the management, metering, and billing/credit control for heat networks. This included reference to social landlords having experienced challenges in management of existing heat networks, although specific examples were not provided.
The nature of the existing built environment was seen as adding to the complexity and cost of heat network installation, particularly for retrofit and where land is under multiple ownership. It was also suggested that installers do not have the rights of other utilities in terms of gaining access to underground infrastructure.
Some respondents and workshop participants felt that knowledge and skills within the supply chain are limited, including in the design and procurement of heat networks. This was regarded as a particular issue in rural and island locations. Some public sector respondents suggested that heat networks are a ‘novel’ technology to many local authorities in Scotland, and that there is uncertainty around operation and maintenance of schemes delivered by public sector organisations. This included suggestions that social landlords have experienced some significant challenges around management of district heating.
Respondents felt that the following were also potential barriers to uptake of heat networks:
- A lack of policy and regulation drivers to encourage installation.
- A lack of strategic planning and coordination between local authorities.
- A lack of consumer awareness and understanding of heat networks, including some concerns around reliability and cost and a perceived lack of consumer protections.
- Application of business rates to district heat infrastructure and energy centre.
Encouraging development of heat networks
Consistent with the barriers noted above, suggested approaches to encouraging development of heat networks focused primarily around policy and legislation, and financial support. Comments are summarised below.
Respondents made recommendations on policy and regulation to encourage investment in heat networks and reassure potential consumers. Specific recommendations included:
- Greater support for heat networks through local planning policy and LHEES including use of heat zoning and targeted policies to identify opportunities for heat networks in off-gas areas.
- Use of Building Regulations to support heat networks.
- Regulation to tackle the issue of ‘demand risk’ for heat network development.
- Technical standards and guidance for heat networks, including at the design and procurement stages.
- Standards and consumer protections around management and billing of heat networks.
- Giving installers of heat networks equal rights of access to other utilities.
- Discouragement of high carbon heating.
- Ensure use of smart meters to improve data available to inform policy and development of heat networks.
- Use of Energy Efficient Scotland to encourage heat networks as an option for consumers in off-gas areas.
- A ‘default organisation’ or national energy company to act as a safety net in the event of a locally managed heat network failing.
- Adapt Greater London Authority Energy Assessment Guidance for use in Scotland.
- Regulation around liability for installation of infrastructure where industrial sites are acting as a heat source.
Respondents’ recommendations for future public funding and other potential financial incentives for heat networks included:
- Continued public funding to encourage heat networks, with sufficient flexibility to recognise design and build timescales. This included a role for the District Heating Loan Fund.
- Supporting access to affordable borrowing for development of heat networks.
- Clear guidance and rules on calculation of heat costs over the long term, including a review of use of counterfactual charges.
- Taxation measures to encourage heat networks.
- Use of the Heat Network Investment Programme to overcome the barrier of capital expenditure.
Wider training programmes and other support were recommended to develop the supply chain. Respondents suggested that this should include better understanding of the risks and benefits of heat networks, and improving access to expert advice and support for developers.
Respondents also perceived a need to raise public awareness of and confidence in heat networks. This included suggestions for sharing of case studies and development of local engagement programmes.
Respondents suggested a range of circumstances and technologies that could improve the viability of heat networks, including:
- Small heat networks in rural off-gas areas.
- Areas where lower cost ‘soft dig’ pipe installation is possible.
- Areas with locally available solid fuel source.
- Clusters of process heat and large buildings in heat networks.
Circumstances suitable for heat networks
A total of 30 respondents (56%) addressed Question 33, and 19 (35%) addressed Question 34.
Comment around circumstances where heat networks may be the most appropriate low carbon solution focused around density of demand and building type or location. This is summarised below.
- One of the most common suggestions was that there is a need for sufficient heat demand to support installation costs. This included reference to a research study indicating that the suitable heat density for heat networks is approximately 3,000kW/m2. A local cluster of large and/or high heat buildings was given as an example.
- It was suggested that building energy efficiency is an important consideration in design of heat networks, although a private sector respondent suggested that heat networks can be designed to decarbonise buildings with poor energy efficiency.
- Building density was commonly suggested as a key feature for heat networks. Respondents also felt there was a range of specific build types, locations and uses where heat networks could be appropriate:
- Off-gas buildings in urban or suburban areas likely to have sufficient heat demand, such as multi storeys, blocks of flats, care homes and student accommodation.
- Use of ‘anchor buildings’ such as leisure centres and hotels to supplement off-peak heat demand.
- Networks with space to deploy thermal storage.
- Areas with mainly stone-free soil where lower cost ‘soft dig’ pipe installation is possible.
- Large brownfield regeneration sites.
- Non-domestic buildings such as hospitals, schools and other public facilities.
- New housing developments (to avoid high retrofit costs).
- Developments where heat networks can incorporate waste heat or heat recovery were also recommended.
- Respondents recommended developments drawing on locally available low carbon fuel supply such as biomass feedstocks, geothermal energy or curtailed wind turbines.
Potential for deployment of heat networks in rural areas was a key theme for some, with respondents expressing a range of views.
Some suggested that heat networks are not a viable option in many rural areas due the factors noted above, most commonly with reference to insufficient density of heat demand. This also reflected suggestions around higher capital costs for rural heat networks due to lower building density and transport costs. Limited local supply chain in rural areas was also suggested as adding to capital costs.
Respondents also saw potential for additional planning restrictions and protected status as barriers to deployment of heat networks in some rural areas. Some suggested that rural heat networks developed to date have typically been on estates with a single land and/or building owner able to manage the process (and minimise ‘demand risk’). A private (other) respondent called for further review of the costs and barriers to rural heat networks before further development is undertaken.
Others suggested that heat networks have been successfully deployed in rural areas, citing evidence that around 10% of heat networks in Scotland are in rural areas. Some wished to see policy and financial support for heat networks across rural and urban areas, for example through support for community ownership and streamlining of planning for heat networks in rural areas.
Respondents suggested a range of factors in support of potential deployment of heat networks in rural areas:
- It was suggested that small heat networks can be economically viable in rural areas, for example where there is relatively high building density and/or access to waste heat. It was also suggested that new housing development in rural areas could provide an opportunity for deployment of heat networks.
- Some suggested that rural areas may be more suitable for heat networks using GSHP (due to availability of external space) and biomass (where there is access to local fuel supply). Opportunity to link with local energy production was seen as a key benefit for heat networks in rural areas.
- Respondents also suggested that fuel poverty rates are higher in rural areas, and that rural communities could be more receptive to the potential for heat networks to deliver cost savings.
Comment and examples provided around moving heat networks to renewable energy are summarised below:
- Respondents suggested that the feasibility and cost of conversion to renewable energy is dependent on heat network design. This included the benefit of central energy centres for future conversion to low carbon heat, and some saw futureproofing of heat networks as important to enable transition to lower carbon and/or lower temperature sources.
- Respondents recommended that heat networks are installed with low carbon heat sources wherever possible. However, some suggested that the current cost of low carbon heat sources can undermine the economic viability of heat networks, and suggested that this may require policy and financial support. This was regarded as a particular issue where installation of low carbon heat is replacing low cost fossil fuels.
- Specific examples of heat networks being moved to renewable energy included small heat networks in rural areas using biomass (particularly with a single owner to manage procurement), an Aberdeen CHP network starting to capture waste heat, later phases of a heat network in Islington using waste heat from the London Underground, and multiple examples across Europe using solar and biomass heat sources.
- In addition the specific examples noted above respondents also suggested other circumstances and/or forms of low carbon heat that could be appropriate for conversion of heat networks:
- Using expansion of a heat network as an opportunity to add low carbon heat sources.
- Shared ground loops are well suited to a range of heat network designs.
- Where biomass feedstocks are available locally.
- LPG and bioLPG can provide a viable source of low carbon heat for some heat networks.
- Where waste heat or heat recovery can be incorporated.
- Evidence was cited that only a small proportion of heat networks currently use low carbon heat.
Gas grid extension
Questions 35 to 37 sought evidence on the continued extension of gas networks. As a lower carbon heat source than heating oil and LPG, expanding the natural gas grid may be an option to reduce emissions in some circumstances. However, in order to meet emission reduction targets natural gas will have to be replaced by low carbon alternatives. Moreover, it is not yet clear whether the whole scale conversion of the gas network to hydrogen or other low carbon alternatives is the most effective way to decarbonise heat.
A total of 32 respondents (59%) addressed Question 35.
Some respondents supported continued extension of gas networks as part of an approach that incorporates all available technologies in the pathway to decarbonising heat. This included reference to use of biomethane and in the future potentially Bio-Synthetic Natural Gas (bioSNG) and hydrogen. It was also suggested that design of any grid extensions would ensure flexibility for future decarbonised gas. Some also suggested that gas grid extension could provide benefits in tackling fuel poverty.
Comments in favour of gas grid extension also appeared to reflect suggestions from some respondents that it may not be feasible or desirable to decarbonise heat wholly or primarily via electrification. Gas network extension was seen as having a role to play in this context, although some wished to see only limited grid extension and others were opposed to any gas grid extension.
Respondents were most likely to have views opposed to or express concerns around continued extension of gas networks. This included the following comments.
- Respondents suggested that significant safety and practicality concerns remain around whole scale introduction of hydrogen or biogas into the current gas network, including reference to a number of reports on the role of hydrogen.. It was suggested that grid extension should not continue until there are proven low carbon solutions to decarbonisation of the gas grid, to avoid risk of stranded assets and wasted expenditure.
- Views were presented that continued extension of the gas grid could delay deployment of low carbon alternatives and could erode the market for these alternatives, putting at risk the net zero target by 2045.
- Some referred to the UK Government commitment to cease new gas grid connections by 2025, and supported a similar approach in Scotland. This included a suggested phased approach to avoid any adverse impacts on tackling fuel poverty.
- It was suggested that viable low carbon alternatives to gas grid extension are already available, and should be given preference over gas grid extension.
Grid extension and wider decarbonisation demands
A total of 17 respondents (31%) addressed Question 36.
Some suggested that gas grid extension would be a cost effective option for industry until viable low carbon options are available. Respondents suggested the potential for this to enable industry to remain competitive, while supporting local employment. Some also suggested that industrial processes could be a suitable focus for introduction of hydrogen and biogas, including reference to an ongoing project looking at this option in Aberdeen.
Respondents suggested a range of considerations that could justify future gas grid extension:
- Where gas grid extension enabled industry to replace use of higher carbon fuels.
- Where industry is co-located with other off-gas domestic or non-domestic buildings.
- Where this incorporates mitigating low carbon technologies such as hybrid systems and smart controls.
Respondents with views opposed to larger scale gas grid extension suggested that many industries and processes can be met by existing low carbon solutions such as bioenergy, bioLPG, and waste heat.
Low gas flows and the existing grid
A total of 7 respondents (13%) addressed Question 37. These respondents cited limited evidence on the viability of the gas grid with low gas flows.
A private (energy supplier) respondent suggested that operational costs of maintaining the gas network with low gas flows would be relatively modest, particularly in comparison with the investment required to establish infrastructure for low carbon alternatives. Respondents also suggested specific aspects of grid maintenance and operation to accommodate low gas flows, including additional maintenance requirements for higher pressure tiers.
Others raised concerns regarding the economic viability of the gas grid with a transition to electric heating, including potential for residual users of gas networks paying a high cost to support the network. Respondents recommended use of the gas grid for electricity generation via fuel cell CHP as a means of maintaining year-round use of the network. It was suggested that a policy decision on decarbonisation of the gas grid was required urgently to provide clarity to technology developers and investors.
Innovation in low carbon heat technologies
The final questions on low carbon heat technologies (Questions 38 and 39) sought evidence on further opportunities for innovation in low carbon heat, and potential for cost reductions.
A total of 18 respondents (33%) addressed Question 38, and 18 (33%) addressed Question 39.
Comments around further developments needed for future market readiness and deployment of low carbon heat reflected some of the themes raised earlier in relation to overcoming barriers to uptake of low carbon heat. This included policy and regulation, funding, and specific marketplace of technological changes. These are summarised below.
- Respondents saw a need for long-term stable policy and regulation to support investment in research and development and energy infrastructure. Specific suggestions included:
- Clarity on the future role of specific technologies such as decarbonisation of the gas grid and bioLPG.
- Gas network companies require clear policy and regulation to support innovation and demonstration projects, and enable market readiness for low carbon technologies.
- Legislation to move gas quality standards from UK legislation to a more flexible industry standard to support greater volumes of lower carbon gas and increases in levels of hydrogen.
- Adoption of a ‘Danish-style’ heat supply policy.
- Removal of regulatory levies from households in remote areas subject to grid constraints.
- Legislation on allocation of profits from any future export of renewable electricity to the grid.
- A range of respondents supported continuation of public financing through a replacement to RHI. Specific suggestions for future financing included a larger upfront payment to enable capital expenditure, a boiler and tank scrappage scheme, and financial support for specific technologies including biogas. Sustained investment into research and development for new technologies and fuels was recommended, including demonstration projects testing introduction of hydrogen to the gas network.
- Some saw a need for more work to improve awareness of low carbon technologies in Scotland, and to target concerns around the cost and disruption of moving to low carbon heat. This included improved understanding of EPCs and the energy performance of buildings.
- Specific projects and other changes recommended by respondents included:
- Further development of time of use tariffs.
- Targeting ‘trigger points’ for promotion of low carbon heat.
- A ‘rolling’ approach to support for individual low carbon technologies that reflects their readiness for market, and allows subsequent technologies to develop.
- Continued investment to upgrade the gas network.
- Changes to how consumers are billed for gas as the network incorporates a growing mix of low carbon gases, including more localised measurement of calorific values.
- Additional investment was recommended to ensure the supply chain and installer base is able to meet increased market demand.
In relation to potential economies of scale and cost savings, some pointed to previous trends in fuel and technology costs (including reference to heat pumps and biofuels) as an indication that running costs will reduce as there is growth in supply and demand for low carbon heat, and increased competition within the supply chain. Further technical innovation was suggested as having potential to continue to reduce running costs, for example through improved efficiency. Some also saw a role for policy and regulation in providing certainty to industry to enable continuing development of technologies, and associated reduction in costs.
Respondents provided specific examples and estimates of economies of scale:
- Cost reductions in biomethane plants through increased deployment in the gas grid and associated economies of scale.
- Significant reduction in costs to install solar PV and wind generation.
- Example of a 3.6% reduction in heat network costs as a result of economies of scale and ‘learning by doing’.
- Estimates of a potential 10-30% fall in heat pump capital costs.
- Estimates of a potential cost reduction of more than 30% for ground source heat pumps.
- Potential for innovation in ground loop systems to continue to reduce costs.
- Potential for futureproofing of new housing development to reduce costs.
However, some suggested there are areas with limited scope for economies of scale to deliver cost reductions, for example mature technologies such as heat pumps. A private (renewables/low carbon) respondent also suggested that negative experience of the solar market has contributed to supply chain businesses being cautious on recruitment, potentially slowing economies of scale.
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