Smart charging involves charging electric vehicles (EVs) at times when demand for electricity and costs are lower. Vehicle-to-Grid (V2G) technology uses smart charging and also enables sending power from an EV back to a house and on to the national grid.

This study investigated V2G opportunities to accelerate the decarbonisation of transport in Scotland compared to smart charging alone. We reviewed global V2G projects to understand potential opportunities in Scotland and carried out modelling to quantify the potential for V2G to accelerate EV uptake.

Findings

• The financial benefits for V2G are strongest for vehicles/fleets with low daily usage and that are charged spanning both peak and low electricity system demand times. However, smart charging without V2G could provide a significant proportion of the benefits that V2G can offer.
• Passenger cars’ low usage relative to commercial fleets yields a strong V2G use case.
• Given that the benefits from V2G depend on infrastructure costs and battery degradation, a comprehensive approach is required to make EV adoption and decarbonisation more feasible.
• High additional value can be achieved from local flexibility services, where consumers are paid by local electricity network operators to adjust their demand, for vehicles such as passenger cars, but the value is highly location specific.
• V2G for commercial fleets would be more feasible by reducing vehicle usage and extending charging windows, which could conflict with their priority of ensuring service reliability.
• Across all vehicle types, a positive use case for V2G may not be sufficient to accelerate EV uptake. Other factors also influence the uptake of EVs, such as upfront costs. V2G further increases the upfront investment required despite adding value in the longer term.

For further details, please read the report.

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

October 2023

DOI: http://dx.doi.org/10.7488/era/4180

Executive summary

Smart charging involves charging electric vehicles (EVs) at times when demand for electricity and costs are lower. Vehicle-to-Grid (V2G) technology uses smart charging and also enables sending power from an EV back to a house and on to the national grid.

This study investigated V2G opportunities to accelerate the decarbonisation of transport in Scotland compared to smart charging alone. We reviewed global V2G projects to understand potential opportunities in Scotland and carried out modelling to quantify the potential for V2G to accelerate EV uptake.

Findings

The estimated net additional value (£ 2023) from V2G compared to smart charging can be calculated as the difference between the revenues from smart charging alone and additional value from V2G. The additional value to vehicle operators for five V2G opportunities we considered are shown in the table below:

In general, we found that:

• The financial benefits for V2G are strongest for vehicles/fleets with low daily usage and that are charged spanning both peak and low electricity system demand times. However, smart charging without V2G could provide a significant proportion of the benefits that V2G can offer.
• Passenger cars’ low usage relative to commercial fleets yields a strong V2G use case.
• Given that the benefits from V2G depend on infrastructure costs and battery degradation, a comprehensive approach is required to make EV adoption and decarbonisation more feasible.
• High additional value can be achieved from local flexibility services, where consumers are paid by local electricity network operators to adjust their demand, for vehicles such as passenger cars, but the value is highly location specific.
• V2G for commercial fleets would be more feasible by reducing vehicle usage and extending charging windows, which could conflict with their priority of ensuring service reliability.
• Across all vehicle types, a positive use case for V2G may not be sufficient to accelerate EV uptake. Other factors also influence the uptake of EVs, such as upfront costs. V2G further increases the upfront investment required despite adding value in the longer term.

Findings for use cases

Specific findings for the three use cases considered in detail in this report with potential additional value included:

• Domestic passenger cars: If V2G installation and maintenance costs remain high in the future, drivers of domestic passenger cars could consider installing V2G solutions from 2025 if they are located in constraint managed zones (area of existing electricity network where network requirements related to the security of electricity supply are met through the use of flexible services), where they will be able to access financial benefits from local flexibility services. Consumers in other parts of Scotland should wait until 2030 before installing V2G solutions. However, if costs of adopting V2G are low, there could be a valuable use case for domestic passenger cars across Scotland from 2025.
• Vans: V2G could be beneficial to vans between 2025 and 2030 if costs of V2G adoption are low or battery degradation from V2G is minimal.
• Trucks: Truck fleet operators are expected to benefit from V2G if low-cost hardware becomes available and battery degradation and maintenance costs are low. High upfront investment could be paid back from 2030 if battery degradation is well managed.

Conclusion

To conclude, accelerated decarbonisation of road transport could be achieved from investment in V2G solutions targeting domestic passenger cars and fleet operators with vehicles that do not have high daily usage and have long overnight charging windows.

Future work and research could focus on removing the barrier of the high upfront infrastructure cost, supporting wider access to flexibility services, and improving understanding and management of battery degradation.

Glossary and abbreviations

Glossary

Abbreviations

AC Alternating current

CMZ Constraint management zone

DC Direct current

DFS Demand flexibility service

DSO Distribution system operator

ESO Electricity system operator

EV Electric vehicle

GHG Greenhouse gas

HGV Heavy goods vehicle

LCM Local constraint market

LGV Light goods vehicle (<3.5t)

RCV Refuse collection vehicle

SPEN Scottish Power Energy Networks

SSEN Scottish & Southern Electricity Networks

V2G Vehicle-to-grid

Introduction

Context

The Scottish government has set ambitious climate change targets. They aim to reduce emissions by 75%, 90%, and 100% compared to 1990 levels by 2030, 2040, and 2045, respectively [1]. Transport is Scotland’s largest source of emissions and in 2021, road transport accounted for 75.5% of total transport emissions (including international aviation and shipping)^[1] [2]. A significant reduction in emissions from the road transport sector will be necessary for Transport to meet its emissions envelope with a rapid transition to zero emission vehicles vital to achieving net zero targets.

Although charging of EVs is currently cheaper than the cost of refuelling Internal Combustion Engine (ICE) vehicles, EV owners and fleet operators are becoming increasingly exposed to the cost of electricity during charging [3]. Innovative charging technologies such as smart or bidirectional charging can play a crucial role in Scotland by further lowering refuelling costs for EVs, with smart charging optimising demand to make the most of low electricity prices and bidirectional charging financially rewarding EVs for discharging into the grid. As such, both smart and bidirectional charging may have the potential to accelerate the pace of transport decarbonisation, lessening impacts of electrification on the power system or even providing net benefits. However, the higher upfront costs and low commercial availability of V2G may act as barriers to adoption.

V2G technology enables the bidirectional charging of EVs, allowing them to charge and discharge energy back to the grid. This capability enables EVs to participate in energy markets and provides wider system benefits to help support the grid during periods of peak electricity demand or supply.

Objectives of the study

The core objective of this study is to understand whether V2G presents opportunities to accelerate the decarbonisation of transport in Scotland, by assessing the potential for V2G to accelerate EV adoption in Scotland.

In this study, we review global V2G projects to understand potential opportunities in Scotland and carry out modelling to quantify the potential for V2G to accelerate EV uptake. Alongside this, we consider the barriers and opportunities to adoption of V2G through engagement with key stakeholders. Full detail on our methodology is set out in Appendix 11.

Assessment of V2G opportunities

Review of global V2G trials

A database of V2G trials was generated from a global literature review, setting out the opportunities examined, the transport sector, geographic location, and context, as well as additional information on duty cycles – the database and summary of the 23 identified trials is shown in Appendix 10.1.

From the global trials, we conclude that:

1. V2G is technically feasible for passenger cars [4], buses [5], and vans [6].
2. V2G would be able to provide grid services to help support Distribution Network Operators (DNOs) across the United Kingdom [7], Europe [4] and North America [8].
3. V2G can offer monetary value for EV owners who can be financially rewarded for discharging electricity back into the grid. The ongoing revenue from the discharged electricity can help lower the total cost of ownership (TCO) of the EV [9].
4. Barriers for V2G rollout include the initial capital cost for charging hardware and installations [9] as well as the timeline and requirements for establishing a grid connection [10].

Assessment of benefits

V2G can offer electricity system and financial benefits by allowing vehicles to participate in energy markets. These benefits can help to alleviate congestion on the electricity grid and reduce carbon emissions from high carbon technologies and through the incentivisation of fleet electrification.

Potential benefits were assessed considering suitability for V2G participation and the financial value for V2G participants. More detail on the potential benefits can be found in Section 10.3 and summarised in Table 1.

Scotland presents unique V2G opportunities owing to the constraint on the transmission network between Scotland and England, as well as local limitations within Scottish & Southern Electricity Networks (SSEN) and Scottish Power Energy Networks (SPEN) networks. Newly introduced flexibility services targeting domestic and commercial consumers, like the Demand Flexibility Service (DFS) and Scotland’s Local Constraint Market (LCM) may offer short-term advantages. As they specifically target small-scale consumers/generators, such as EVs, the DFS and LCM have lower barriers to entry than other flexibility markets, such as the Balancing Mechanism. Therefore they could offer value for V2G in the short-term, while access to other flexibility markets is still prohibitive. However, participating in these services in the long term could limit the potential value of V2G as the barriers to enter other flexibility markets are overcome.

Currently, it is not possible to participate in the DFS or LCM alongside other flexibility services, such as the Balancing Mechanism, which can generate assets more value over the course of the year. Although it is possible that this restriction will be lifted in the future to allow participation in these markets alongside other flexibility markets, it is not confirmed and the required conditions are not clear. As a result, in the short term V2G could access value from participating in the consumer-targeted services such as the DFS and LCM. However, it is not clear if participation in these markets will be valuable in the long-term, as consumers may be able to make more revenue in the future from participating in a combination of other flexibility services, such as the Balancing Mechanism.

Assessment of costs

Cost of chargers

V2G business models currently incur higher costs relative to smart chargers. Smart chargers are unidirectional and are able to intelligently manage how much energy to give to a plugged-in EV. This study considers smart charging as the baseline case, as smart charging is assumed to be the standard in the UK, considering the Electric Vehicles (Smart Charge Points) Regulations 2021, which stipulates that electric chargers sold in Great Britain must have smart functionality [11]. In contrast, the greater functionality of bidirectional chargers (used for V2G), which can feed energy into the grid, incurs higher costs mainly due to increased hardware and installation expenses, along with added battery degradation and maintenance costs. More detail on the potential costs can be found in Section 10.4.

There is limited data on the cost of V2G chargers in literature, although estimates can exceed twice the cost of smart EV chargers, with smart chargers costing £1,400 and V2G chargers costing £4,160, as shown in Figure 1 [12].

Figure 1: Estimated hardware and installation costs (£ 2023) for a smart charger compared with a DC bidirectional charger. These have been calculated from data in the literature [12].

Battery degradation

Research is currently ongoing to assess the impact of bidirectional charging on battery degradation, with the exact effect still uncertain. Battery degradation includes both cycling and calendar fade. Cycling degradation of a battery occurs due to the use of the battery (number of charging and discharging cycles) while calendar degradation occurs from a fade in capacity over time. Calendar degradation can be further exacerbated by leaving the battery at 0% or 100% charge [13].

Most studies suggest that V2G systems may accelerate degradation, mainly due to the increased annual cycling of batteries (cycling degradation rather than calendar degradation) [13]. The extent of this cycling depends on the charging and discharging cycles of the batteries. This degradation can lead to a reduction in an EV’s range and potentially necessitate battery replacement during the vehicle’s lifespan, which represents an additional cost and might discourage consumers.

Conversely, some sources propose that V2G systems could preserve battery state of health [14]. Calendar degradation is directly influenced (along with other factors) by the state of charge at which the battery is held. Bidirectional charging, along with proper battery management strategies, can help mitigate calendar degradation by maintaining the state of of charge of the battery at a more optimal value. This could balance the effect of increased cycling from V2G, and potentially prolong the battery life.

To account for the ongoing research to understand the impact of bidirectional charging on battery degradation, two scenarios were modelled to represent the cost of increased battery degradation as a result of V2G, expressed as a cost per MWh discharge. Full details of the findings on battery degradation can be found in Appendix 10.4.2.

Analysis of V2G use cases

V2G use cases

Rankings based on emissions contribution, fleet size, and financial savings and other benefits were used to determine the opportunities with the biggest impact (Table 2). These include passenger cars at home, vans in an urban depot, RCVs in an urban depot, rigid trucks in an urban depot and buses in an urban depot. The use cases are assumed to be within an urban environment due to the likely value of local constraint alleviation and the expected duty cycles.

Further details on the assessment of opportunities can be found in Section 10.2. The detailed development of each use case, including modelled carbon emissions savings from a fully electrified fleet, expected infrastructure costs and projected additional value, is set out in Section 6. Furthermore, priority areas were aligned with Transport Scotland which informed the final selection of the five use cases.

Table 2: Five use cases selected on basis of V2G opportunities in Scotland. Selection based on road transport emissions [15, 16, 17], registered passenger vehicles [18], and available benefits.

Charging behaviour

A combination of data from literature and stakeholder engagement was used to determine the potential battery capacity available and timeframe for V2G participation. Data is based on average daily charging demand, battery size, and charging windows. A summary of the assumed charging demand for each use case is shown in Figure 2, and the charging window is shown in Figure 3.

Figure 2: Daily charging demand of different vehicle types (kWh/day) modelled for each use case [19, 20, 21, 22, 23].

As shown in Figure 2, passenger cars and vans are modelled as having the lowest daily charging demand at 4.8 kWh/day and 14.5 kWh/day respectively. They also have similar charging windows, with cars plugging in between 5.30pm and 8am and vans plugging in between 7pm – 8.30am, as shown in Figure 3.

Buses are modelled as having the highest daily charging demand at 229.9 kWh/day, and have the shortest charging window of 5.5 hours, as shown in Figure 3. RCVs have the longest plug-in time of 15.5 hours, but also the second highest daily charging demand of 213 kWh/day. Trucks have a moderately high charging demand of 81 kWh/day as shown in Figure 2, but a long overnight charging window of 12 hours.

Figure 3: Assumed hourly breakdown of the charging windows for each use case. A full line indicates when the respective vehicles are plugged in and can participate in V2G [24, 25, 26].

Additional value from V2G

The charging profiles for each use case were modelled to understand the additional value that can be achieved with either smart charging alone or with V2G. In the same way that smart chargers have been chosen as a baseline for the costs, smart charging has been chosen as a baseline for determining the additional value from V2G (as per the charging smart charging regulations).

The modelled additional value was calculated considering the availability of:

1. Energy arbitrage (considering electricity prices on the wholesale market) and the Balancing Mechanism, in addition to on-site renewable generation.
2. Local flexibility services for the DNO.
3. Consumer flexibility services, including the DFM and Scotland’s LCM. It should be noted that consumer flexibility services cannot currently be stacked with the Balancing Mechanism.

Further detail on the method for modelling of the additional value can be found in Appendix 11. The modelled additional value compared to smart charging for each of the five use cases when participating in V2G is shown in Figure 4.

Figure 4: Modelled additional value (£ 2023) for each use case from V2G broken down by financial benefit.

For buses and RCVs, the additional value achieved with V2G compared with smart charging is only generated through participation in consumer flexibility services. Electric buses and RCVs generate significant revenue from the Balancing Mechanism when smart charging but is not able to generate further Balancing Mechanism revenues through V2G.

As shown in Figure 4, passenger cars, vans and trucks generate the majority of additional value from V2G through energy arbitrage, considering both the wholesale electricity market and the Balancing Mechanism. Passenger cars are able to generate further additional value through participation in local flexibility services. While all use cases are modelled to participate in local flexibility services through smart charging alone, only passenger cars have sufficient battery capacity at the beginning of their charging window to discharge over the evening peak required for local flexibility services.

Modelling of the additional value showed that participation in flexibility services with smart charging alone produced significant additional value for all use cases. This is detailed further in Section 6.

Deep dive on the use cases

Use case 1: Domestic passenger cars

Passenger cars were selected as a use case offering V2G at home. Passenger cars comprise 82% of Scotland’s road vehicle fleet and contributed 53% of road emissions in 2021, making them the most significant vehicle type in both categories [15]. Electrifying this fleet in Scotland would lead to significant carbon emissions savings, amounting to a total reduction of 4.62 MtCO₂ as shown in Figure 5.

Figure 5: The reduction in carbon emissions from road transport from a fully electric fleet of passenger cars in Scotland.^[3]

The estimated daily energy use for passenger cars is 4.8 kWh, leaving 46.2 kWh of available energy for V2G participation (Appendix 11.5.1). Figure 6 illustrates the average charging profile for passenger cars, with a charging window from 5:30 pm to 7:30 am.

Figure 6: Showing the average charging power and timeline for when the electric passenger car is plugged in [24] along with a dynamic tariff in Southern Scotland [27].

Figure 7 displays the modelled additional value from energy arbitrage and participation in flexibility services, showing that V2G generates higher value compared to smart charging alone. Passenger cars using V2G can gain additional value by discharging during evening hours and recharging when electricity prices are at their lowest, typically between 12 am and 4 am.

The additional value potential of V2G for passenger cars is predominantly from energy arbitrage and local flexibility services. Given their specific duty cycles and plug-in times, passenger cars offer a substantial surplus of energy when plugged in overnight, which can be used for engagement in wholesale energy arbitrage, the Balancing Mechanism and local flexibility markets. If in the future consumers are able to access consumer flexibility services, including the Scotland specific LCM, alongside other flexibility services they may be able to access a small amount of further additional value.

Figure 7: Composition of modelled additional value (£ 2023) to consumers for both smart charging and V2G charging for passenger cars. Note: dotted box shows the potential additional value from participation in Consumer flexibility services if in the future these could be stacked alongside other flexibility services.

Figure 8 shows the hardware and installation costs of V2G chargers, these have been modelled within a high or low-cost scenario which is described in further detail in Section 11.5.3. Passenger cars are assumed to use a 7-kW charger, which is lower cost than higher-power chargers.

Figure 8: Associated costs (£ 2023) for hardware and installations for a 7 kW AC charger in 2025 and 2030.

Passenger cars participating in V2G services could stimulate EV uptake due to the financial advantages they offer while simultaneously delivering net system benefits through local and consumer flexibility services during peak demand. There is a strong case for passenger cars to participate in V2G under the assumptions considered.

Use case 2: Vans in an urban depot

Vans fall into the category of LGVs which comprised 11% of registered vehicles in Scotland in and contributed to 20% of Scottish road-based emissions in 2021. The urban context was chosen as approximately 58% of LGVs in Scotland were situated in urban areas in 2021 [18] [28].

Figure 9: The reduction in carbon emissions from road transport from a fully electric fleet of LGVs in Scotland.^[4]

Figure 9 shows the carbon emissions savings achievable from a fully electrified van fleet, resulting in a total reduction of approximately 1.75 MtCO₂.

Figure 10: The average charging power and timeline for when the electric van is plugged in [28] along with a with a dynamic tariff in Southern Scotland [27].

Figure 10 shows the average charging power profile for vans. The charging window is from 7 pm to 8:30 am (UK Power Networks, 2022). The average daily energy consumption for vans is estimated at 14.5 kWh, calculated from average daily mileage and electricity consumption data provided in Appendix 11.5.1.

As shown in Figure 11, V2G participation for vans offers a source of moderate additional value as their duty cycles allow them to engage in both wholesale electricity market and the Balancing Mechanism through energy arbitrage overnight. However, modelling shows that the electric van battery would be expected to be almost depleted when plugging in, thus they are unable to offer local flexibility services over the evening peak. If in the future consumers are able to access consumer flexibility services, including the Scotland specific LCM, alongside other flexibility services they may be able to access a small amount of further additional value.

Figure 11: Composition of modelled additional value (£ 2023) to consumers for both smart charging and V2G charging for vans.

The cost of hardware and installation of V2G chargers, as shown in Figure 12, is the same as that for passenger cars, assuming a 7 kW AC charger. The costs have been modelled within a high or low-cost scenario which is described in further detail in Section 11.5.3

Figure 12: Associated costs (£ 2023) for hardware and installations for a 7 kW AC charger in 2025 and 2030.

Electric van fleets across the UK are expected to have highly varied duty cycles with differences in mileage, operating radii, and charging opportunities [29] and therefore will have differing opportunities to benefit from V2G. Furthermore, fleet operators may currently be apprehensive to adapt their operating schedules to participate in V2G. However, if V2G is able to provide ongoing revenues to fleets, this may encourage operators to electrify their fleets by reducing the total cost of ownership [26].

Additionally, findings indicate that the costs of hardware and installation pose significant barriers for small firms with limited resources to invest upfront in charging infrastructure and electric vehicles [29]. Further findings from this study highlighted that vans that charged at home, especially those belonging to small businesses, are likely to face higher prices to charge their EV. V2G will require higher upfront investment, however, the additional value for participation in V2G could help to reduce both the cost of charging and transition.

With the assumptions made here, V2G participation is likely to provide financial benefits, given the duty cycles of vans in urban environments. However, the additional upfront cost of infrastructure could be a barrier.

Use case 3: Trucks in an urban depot

Rigid trucks fall within the vehicle category of HGVs. These vehicles constituted 1.2% of registered vehicles in Scotland in 2021, contributing to about 21% of Scottish road-based emissions in 2021 [18]. The urban context was chosen given that approximately 61% of HGVs in Scotland were situated in urban areas in 2021 [30]. Figure 13 shows the potential carbon emissions savings from a fully electrified fleet of rigid trucks, estimated at approximately 1.80 MtCO2.

Figure 13: The reduction in carbon emissions from road transport from a fully electric fleet of HGVs in Scotland.^[5]

Figure 14 illustrates the average charging power profile for an urban rigid truck, with a charging window spanning from 5 pm to 5 am [25]. The average daily energy consumption for these trucks is estimated at 81 kWh, calculated from average daily mileage and electricity consumption data in Appendix 11.5.1. The remaining available battery capacity, coupled with the charging window, creates an opportunity for the truck to participate in V2G upon its return to the depot for charging, as shown in Figure 14.

Figure 14: The average charging power and timeline for when the electric truck is plugged in [25] with a dynamic tariff in Southern Scotland [27].

As shown in Figure 15, the additional value from V2G is mainly from energy arbitrage, including wholesale market and Balancing Mechanism participation. The additional value from on-site renewables is negligible when comparing smart charging and V2G charging. If in the future consumers are able to access consumer flexibility services, including the Scotland specific LCM, alongside other flexibility services they may be able to access a small amount of further additional value.

Rigid trucks are assumed to use a 22 kW AC charger. Projections for the costs of hardware and installation for such chargers in 2025 and 2030 are displayed in Figure 16.

Figure 15: Breakdown of modelled additional value (£ 2023) for trucks for both smart charging and V2G.

Figure 16: Associated costs (£ 2023) for hardware and installations for a 22 kW AC charger in 2025 and 2030.

While a positive use case for V2G could incentivise the electrification of trucks, insights from stakeholder engagement sessions suggest that truck fleet operators tend to prioritise high utilisation of their trucks to maximise revenues from existing operations. V2G would be viewed as a secondary priority and may not align with the primary business model.

Further barriers to V2G adoption are associated with the costs of V2G installations and the necessity for grid upgrades to support V2G. Stakeholder discussions indicated these investment costs to be approximately £350,000 (£ 2023), which serves as a significant hurdle for the widespread uptake of V2G.

While V2G participation has the potential to incentivise electric vehicle adoption, the incompatibility between duty cycles and charging requirements decreases the use case of V2G decarbonisation of emissions for the Scottish truck fleet.

Use case 4: Buses in an urban depot

In 2021, buses accounted for 1.2% of road-based emissions in Scotland [2] while approximately 71% of buses in Scotland were located in urban areas in 2021 [15].

Figure 17: Reductions in carbon emissions from road transport from a fully electric fleet of buses in Scotland. ^[6]

Figure 17 shows the potential carbon emissions savings from a fully electrified fleet of buses, estimated at approximately 74 ktCO₂. Urban buses’ daily energy use is estimated to be 230 kWh, as calculated from average daily mileage and electricity consumption in Appendix 11.5.1.

Figure 18 illustrates the average charging power profile for urban buses, with a charging window between 12 am and 5:30 am [25]. This charging window reflects the operation in a major German city and has been confirmed by a discussion with a major bus operator. The duty cycles of urban buses can be highly variable, ranging from 14 to 22 hours of daily use, making it difficult to model in terms of V2G.

Figure 18: Average charging power and timeline for when the electric bus is plugged in [25] along with a with a dynamic tariff in Southern Scotland [27].

The potential for additional value from V2G participation is significantly limited as the battery of an electric bus is expected to be depleted on return to the depot. This limits the capacity for V2G to take place over the charging window and leads to no additional value from V2G compared to smart charging alone, as shown in Figure 19. If in the future consumers are able to access consumer flexibility services, including the Scotland specific LCM, alongside other flexibility services they may be able to access a small amount of additional value from V2G.

Figure 19: Breakdown of modelled additional value (£ 2023) from buses for both smart charging and V2G.

Longer plug in times were modelled for buses as a sensitivity. Within this sensitivity, an increased the plug-in time, from 8pm – 12am was found to have no impact on the additional value that V2G could offer.

V2G integration with buses is technically feasible, as shown in a previous proof-of-concept trial [5]. However, operational challenges arise, primarily ensuring that the buses are adequately charged for their respective duty cycles. To benefit from the potential additional value offered by V2G, bus operators may need to adjust duty cycles, including reducing daily mileage, to have more energy available for V2G participation. Such changes would impact the utilisation of the bus fleet, potentially affecting the existing business model of fleet operators.

Figure 20: Associated costs (£ 2023) for hardware and installations for an 80 kW AC charger in 2025 and 2030.

As shown in Figure 20, the costs associated with hardware and V2G charger installation are influenced by the high power of the chargers, as buses are assumed to use an 80 kW AC charger. The higher charger power significantly escalates the hardware and installation costs. Cost reductions associated with charging hardware and installations are essential for the V2G use case.

While V2G participation has the potential to drive electric vehicle adoption, the incompatibility between duty cycles and charging requirements decreases the use case of V2G decarbonisation of emissions for the Scottish bus fleet.

Use case 5: RCVs in an urban depot

RCVs are classified as a type of HGV which represented 1.2% of registered vehicles in Scotland in 2021 and with an estimated contribution of 0.5% of road-based emissions in 2021 [15]. The urban setting was chosen because approximately 61% of HGVs in Scotland were located in urban areas in 2021 [30]. There are an estimated 1,246 RCVs in Scotland representing 7% of the UK fleet [31, 17]. The potential carbon emissions savings from a fully electrified RCV fleet are estimated at approximately 0.020 MtCO₂ as shown in Figure 21.

Figure 21: The reduction in carbon emissions from road transport from a fully electric fleet of RCVs in Scotland.^[7]

Figure 22 shows the average charging power profile for RCVs, with a charging window spanning from 3:30 pm to 7 am [32, 25].

Figure 22: The average charging power and timeline for when the electric RCV is plugged in [25] along with a with a dynamic tariff in Southern Scotland [27].

The duty cycle of RCVs places limitations on the achievable additional value through participation in V2G markets, as shown in Figure 23. This is due to the energy intensity of the industry which is constrained by both mileage and uplift requirements for the waste collection service. When compared to passive charging, smart charging offers considerable value, however, V2G does not provide further value. If in the future consumers are able to access consumer flexibility services, including the Scotland specific LCM, alongside other flexibility services they may be able to access a small amount of additional value from V2G.

Figure 23: Breakdown of modelled additional value (£ 2023) for RCVS participating in both smart charging and V2G.

A charger power rating of 50 kW was assumed, as per stakeholder engagement with a Scottish City Council. This results in higher costs relative to slower chargers, as shown in Figure 24.

Figure 24: Associated costs (£ 2023) for hardware and installations for a 50 kW AC charger in 2025 and 2030.

Scottish city councils, including Edinburgh and Dundee, are actively exploring the electrification of their RCV fleets. Stakeholder engagement suggests that even if a fleet is open to innovative charging infrastructure and energy system technology, the reliability of the waste collection service remains the highest priority. The primary focus currently lies in electrifying the fleets while ensuring that the operations of the electric vehicles align with the required duty cycles. Exploration of V2G opportunities may be considered for a later stage if a strong use case for participation is established [33], such as through low infrastructure costs and improved revenue opportunities.

While further participation in V2G services could promote the adoption of electric RCVs, the duty cycles of RCVs make them less suitable for V2G.

V2G use case modelling

The V2G use case was further investigated for vehicle types with the highest modelled additional value (passenger cars, vans in an urban depot, and trucks in an urban depot). The use case was assessed through cash flow modelling, combining the modelled additional value over smart charging from V2G with the expected costs of the V2G solutions. The additional value from V2G is the value above smart charging. High and low-cost scenarios were developed, considering the uncertainty in future hardware and installation, battery degradation, and maintenance costs. Further detail on the cost scenarios is set out in Appendix 11.5.3.

For each use case, the potential for V2G adoption was modelled assuming the technology was installed in either 2025 or 2030 and assumed a 15-year lifetime of the hardware [12]. Further detail on the uses case modelling assumptions is set out in Appendix 11.5.4.

Domestic passenger cars

Across both the high and low-cost scenarios, domestic passenger cars see a favourable use case for V2G. As shown in Figure 25, the investment under the high-cost scenario is paid back within 5 years if installed in 2025, and in 2 years if installed in 2030. In the low-cost scenario, the investment is expected to be paid back within one year in both 2025 and 2030.

Figure 25: Payback period (years) for domestic passenger cars installing V2G solution in 2025 and 2030 in high and low-cost scenarios, and sensitivity to availability of additional value from local flexibility service.

However, a large proportion of the modelled additional value for passenger cars comes from local flexibility services. Additional value from local flexibility services is location dependent and is therefore only available to customers in Scotland’s CMZs. As set out in Section 5.3, Scotland’s CMZs present high value services especially in locations where upgrades to the network are expensive, such as in urban locations or extremely remote areas. We investigated the sensitivity to this to understand the use case for V2G without the additional value. These results are set out in Figure 25, and show that the use case is less favourable under the high-cost scenario for customers outside Scotland’s CMZs. In such cases, there is no anticipated payback within the assumed 15-year lifetime of the hardware if V2G is installed in 2025, and a 6-year payback if installed in 2030. Conversely, in the low-cost scenario, the additional value from local flexibility services has a lower impact on the use case. A 2-year payback on investment is achieved when V2G is installed in 2025 and 1 year if installed in 2030.

Key findings for passenger cars

• The use case for passenger cars, or for light duty fleets with low daily mileage and with charging windows that span 5.30pm – 8am, is favourable across both high and low-cost scenarios.
• If V2G installation and maintenance costs remain high in the future, installing V2G solutions for domestic passenger cars, even for those in CMZs with access to high additional value from local flexibility services, may not be economically viable until 2025. For those outside CMZs, it will not be cost effective to install V2G solutions until 2030. However, if V2G installation and maintenance costs decrease in the future, V2G adoption could be an effective use case for domestic passenger cars across Scotland from 2025.
• Consumers are highly sensitive to upfront costs [34] and EV uptake related to passenger cars is likely to be limited by supply constraints not consumer willingness, therefore additional value from V2G may not accelerate uptake [35].
• Accelerating the uptake of electric passenger cars can offer significant carbon emissions savings considering that passenger cars are responsible for the largest proportion for Scottish road transport emissions.
• To participate in V2G, customers would need to consider the potential of reduced available energy after charging windows. They will also need to understand the impact of potential battery degradation due to increased cycling.

Vans in an urban depot

For vans, if V2G installation and maintenance costs are lower in the future, there is a good use case for installing V2G solutions for vans from 2025 onwards. As shown in Figure 26, the investment in V2G is expected to be paid back within 2 years if installed in 2025, and within 1 year if installed in 2030.

Figure 26: Payback period (years) for vans in an urban depot installing V2G solution in 2025 and 2030 for high and low-cost scenarios, and a sensitivity considering high upfront and ongoing maintenance costs, but low degradation costs.

However, if the V2G installation and maintenance costs are not lower, V2G is not a favourable use case for vans in 2025 or 2030. As shown in Figure 26, there is no payback for the V2G solution within the assumed 15-year hardware lifetime with high costs in either 2025 or 2030. The use case is particularly sensitive to the cost of battery degradation, as vans require high V2G discharge to receive additional value. A sensitivity analysis was applied using hardware and installation and maintenance costs from the high-cost scenario, but battery degradation costs from the low-cost scenario (detail provided in Appendix 11.5.3). As shown in Figure 26, this improves the use case, with installation of a V2G solution in 2025 being paid back within 11 years and installation in 2030 leading to a payback of 5 years.

Key findings for vans

• V2G could be beneficial to vans over 2025 – 2030, if installation and maintenance costs are low or if battery degradation from V2G is minimal.
• The use case for vans, or other light duty fleets with high daily mileage and overnight charging, is improved from 2025-2030 if costs are low or battery degradation is minimal.
• Vans that are returned to drivers’ homes instead of depots are more likely to belong to smaller businesses and are likely to benefit from an improved use case for electric vans [36]. However, these customers are also more sensitive to upfront costs [29].
• V2G could accelerate the uptake of electric vans between 2025 and 2030, but operators may need support to cover the increased upfront costs.
• To participate in V2G, customers would need to consider limiting operation to increase available battery capacity. They will also need to understand the impact of potential battery degradation due to increased cycling.

Trucks in an urban depot

For trucks, in the low-cost scenario, the investment in V2G would be paid back within 4 years if installed in 2025, and 2 years if installed in 2030. However, if costs are high, trucks are unlikely to benefit from V2G. As shown in Figure 27, there is no payback achieved within the assumed 15-year lifetime under the high-cost scenario when V2G solutions are installed in 2025 or 2030.

A sensitivity analysis was carried out to understand the impact of battery degradation on the V2G use case. Sensitivity was assessed using hardware and installation and maintenance costs from the high-cost scenario, but degradation costs from the low-cost scenario (detail provided in Appendix 11.5.3). As shown in Figure 27, this resulted in no payback within the lifetime of the hardware installed in 2025 but led to a 6-year payback period for infrastructure installed in 2030.

Figure 27: Payback period (years) for trucks in an urban depot installing V2G solution in 2025 and 2030 over high and low-cost scenarios, and sensitivity considering high upfront and ongoing maintenance costs, but low degradation costs.

Key findings for trucks in an urban depot

• Truck fleet operators are expected to benefit from V2G if low-cost hardware becomes available and degradation and maintenance costs are low. However, high upfront investment could be paid back from 2030 if degradation is well managed.
• The use case for rigid urban trucks, or other heavy-duty fleets with moderate mileage and overnight charging, is improved from 2030 if costs are low or battery degradation is minimal.
• Nevertheless, rigid urban trucks are expected to already reach battery electric vehicle total cost of ownership parity with internal combustion engine equivalents between 2020 – 2025 [37]. Consequently, V2G may not significantly accelerate uptake further.
• Trucks with higher mileage and utilisation would struggle to benefit from V2G considering the short charging windows between duty cycles.
• Stakeholder discussions indicate that high upfront costs are a significant barrier to electrification, and V2G would exacerbate this despite the potential value it offers.
• To participate in V2G, customers would need to consider limiting operation to increase available battery capacity. They will also need to assess the impact of potential battery degradation due to increased cycling.

Assessment of the potential for V2G to accelerate EV uptake in Scotland

Conclusions on the use case for V2G in Scotland

We found that investment in V2G solutions could be beneficial for fleets that do not have high daily usage and have long overnight charging windows. However, smart charging without V2G, considered as the baseline taking into account regulations on EV charging infrastructure beyond 2021, can already provide a significant proportion of the value that V2G can offer. For some vehicle operating cycles, V2G is likely to offer marginal additional benefits over smart charging, especially when accompanied by a significant upfront investment in infrastructure.

Key findings on the V2G use cases included:

1. The use case for V2G is strongest for vehicles/fleets that exhibit low daily usage and that are charged spanning both peak and low electricity system demand times.

• Duty cycles of vehicles strongly influence the V2G use case. V2G has higher additional value potential for vehicles with low mileage and electricity consumption, and that are charged both during evening electricity demand spikes and overnight low system demand.
• The potential for V2G is also highest for vehicles that have remaining battery capacity after their daily duty cycles:
  • For instance, passenger cars that have a significant proportion of remaining battery capacity for V2G at the start of their charging window in the evening. These vehicles are therefore able to discharge during the evening when electricity demand and prices are highest, and local flexibility services are most valuable.
  • Fleets with similar charging windows and surplus battery capacity post-duty cycles can benefit from V2G in a similar manner to passenger cars.
• The use case for V2G is not as strong for higher usage vehicles such as vans, buses, RCVs and trucks, which have both higher average daily mileages and electricity consumptions. This limits the available battery capacity for V2G.
• Furthermore, commercial vehicles such as vans, trucks, RCVs and buses face limitations due to the priority of maximising fleet utilisation, which restricts available energy for V2G and the time that EVs can participate in V2G. While V2G could drive EV adoption for commercial fleets through additional revenues, they are likely to prioritise service reliability.

1. High additional value is available from local flexibility services for vehicles such as passenger cars, but the value is highly location specific and will primarily depend on whether V2G occurs within one of Scotland’s CMZs.

• Our use case modelling showed that passenger cars may be able to participate in local flexibility services within CMZs, which can unlock location specific value. This additional value has a large impact on the use case for adoption of V2G by battery electric passenger cars, or other light duty vehicles with low daily operation and that are charged during the evening peak times. This may therefore accelerate the uptake of EVs.
• Without participation in local flexibility services, the use case for V2G for these vehicles is weakened. Therefore, future V2G business models may target vehicles with an operating cycle within CMZs where local flexibility services are offered by DSOs.
• Current CMZs are situated in grid areas that need flexibility for security of supply; future CMZs are likely to be in zones with high renewable energy generation and/or high electricity demand, although their specific future locations are uncertain.
• Current CMZs identified by SSEN and SPEN are distributed across urban areas including Edinburgh and Dundee, rural regions such as the Highlands and islands including Arran, Lewis and Harris.

1. The V2G use case is sensitive to infrastructure cost and battery degradation and a positive V2G use case alone may not be sufficient to accelerate EV uptake. Other factors also influence the uptake of EVs, such as upfront costs and supply chain constraints.

• When compared to smart charging infrastructure, the cost of bidirectional charging infrastructure is a significant barrier to V2G adoption, particularly for upfront-cost-sensitive customers and fleet operators. Fleet operators have reported that the high upfront cost of unidirectional charging infrastructure is a barrier to electrification, and installing V2G infrastructure further increases the upfront investment required.
• The V2G use case additionally depends on managing the cost of battery degradation due to increased cycling of vehicle batteries. These costs must be better understood by consumers and fleet operators before they can commit to V2G business models.
• Lower infrastructure costs and improved understanding of battery degradation costs can improve V2G business models, potentially accelerating the decarbonisation of transport through greater EV adoption.

Summary of findings

Table 3 presents a summary of the findings for the use cases analysed within this study. It outlines the costs, benefits, opportunities and suitability of V2G for each use case. The quantifiable benefits of V2G are given as annual financial benefits and potential emissions reductions from increased electrification. Additionally, V2G also offers further benefits, such as the potential decarbonisation of the electricity grid through the incorporation of additional renewable generation, which were not included in the scope of this study.

Recommendations on further research and support

This section outlines recommended areas for further research and support to increase V2G uptake in order to accelerate decarbonisation.

1. Support is required to remove the high upfront cost barrier to V2G uptake.

• The high upfront cost of purchasing unidirectional charging infrastructure is a barrier to electrifying certain vehicle types, particularly those that which require high power ratings (trucks, buses and RCVs). The costs are further exacerbated by the extra premium incurred from bidirectional (V2G) hardware.
• Further research and support are necessary to reduce the upfront investment required for V2G solutions, for example through scaling of manufacture and commercial development of lower cost technologies such as bidirectional AC charge points.
• Alternatively, future work could be targeted at providing support incentives to promote investment in V2G infrastructure, although it would be important to ensure that the support targets transport segments that would have high utilisation of V2G.
• Encouraging the development of business models which involve shared bidirectional charging infrastructure would reduce the upfront investment for participating members. Although this could lead to feasibility issues around charger availability, it would add an additional revenue stream for the owners of the V2G chargers.

1. Improve the ability for EVs to access flexibility value through initiatives such as Balancing Mechanism Wider Access.

• The use case for V2G is dependent on being able to access value from flexibility services, including the Balancing Mechanism and local flexibility services.
• Currently, some market access rules are pose barriers for distributed assets, despite their technical suitability, or stacking of value streams is prohibited, e.g., with the LCM and DFS.
• Improving access to flexibility markets for customers is a major area of research, and initiatives such as ESO’s Balancing Mechanism Wider Access aims to maximise the resources available on the electricity system, while delivering value to energy consumers [38]

1. Further research is required to improve the understanding of battery degradation from V2G and develop management strategies for minimisation.

• The effect of battery degradation and the associated cost is a key aspect of the V2G use case. To build an effective use case, vehicle owners and fleet operators will need to understand how V2G affects the battery state of health and the incurred cost from these effects.
• Additionally, minimising battery degradation has a significant impact on the use case for V2G, and therefore effective management will be valuable for the uptake of V2G.

References

Appendix: Further detailed analysis

Identified V2G trials

The literature review resulted in 23 identified projects that explored V2G across various vehicle types and locations. The trials were primarily concentrated in the UK and other parts of Europe, including Denmark, Belgium, France, Switzerland, Italy, Greece, and Germany. As shown in Figure 28, the identified trials were mainly located in public charge points or depots, although some at home or work locations were found. The trials involved mainly passenger cars (64%) but light goods vehicles (LGVs) and heavy goods vehicles (HGVs) also featured. Most trials were categorised as commercial with less than a third covering domestic transport.

The trial name, description and source are given in Table 4. Deep dives on four key examples of trials are described in Appendix 10.1.1.

Deep dives on key trials

Deep dives on four key examples of trials are shown below, to illustrate the information collected and the variety of projects considered. The deep dives include JumpSmartMaui [48], Nottingham City Council [61], Project Sciurus [39] and Bus2Grid [62].

Nottingham City Council

Summary:

This project uses V2G enabled refuse collection vehicles (RCVs) to offer flexibility services and maximise consumption of on-site renewables.

Trial information:

• Nottingham City Council and Connected Energy have installed 40 V2G chargers in an urban depot containing 250 EVs including 6 electric RCVs.
• The trial aims to decarbonise operations of the depot using EVs coupled with V2G and on-site PV generation.

Benefits identified:

• The ongoing project aims to use the electric fleet and V2G to isolate the depot during peak demand and avoid peak tariffs.

JumpSmartMaui

Summary:

Passenger cars were used for V2G to store excess renewable energy and provide flexibility services to the DNO in Maui.

Trial information:

• Hitachi supplied 200 passenger cars to volunteers.
• 80 chargers were installed in rural households and urban public carparks across the island.

Benefits identified:

• EV charging times were shifted to align with excess electricity from renewables.
• V2G was used to discharge into the grid during hours of peak demand.

Bus2Grid

Summary:

This project used electric buses and V2G to offer aggregated capacity in a depot in London.

Trial information:

• Go-Ahead, London’s largest bus company, operates 28 BYD/ADL Enviro 400EVs at the UK’s largest electric bus depot.
• Exploring V2G for commercial benefits, including frequency response and energy arbitrage.

Benefits identified:

• Project was the first demonstration of V2G from e-buses, demonstrating >1 MW of aggregated capacity.
• V2G was used to discharge into the grid during peak demand hours.

Project Sciurus

Summary:

This project utilised passenger cars and V2G to demonstrate that V2G technology works at a residential level.

Trial information:

• 320 V2G units were installed in real homes across the UK.
• Kaluza developed a platform for optimal charging and discharging times based on the customer needs.

Benefits identified:

• EV charging times were shifted from peak demand to when the grid would have excess supply from RES.
• V2G was used to discharge into the grid during peak demand hours.

Development of V2G opportunities

V2G opportunities identified from the trials identified from the literature included vehicle type, geographical context, charging window and local environment, as shown in Table 5.

We identified twelve distinct V2G opportunities for further assessment. The list of V2G opportunities, including a high-level description of the charging window and local environment, is presented in Table 6. In this study, the term ‘trucks’ refers to urban rigid heavy goods vehicles, which we assume as typically used for last mile distribution to stores (typically 18t or 26t rigids).

Assessment of opportunities

Financial savings and other benefits identified in the literature were used to categorise each V2G opportunity as either a high, medium, or low benefit. Benefits include financial savings from grid services, energy arbitrage (described in Section 10.3.1), and integration of on-site renewables. Additionally, other benefits such as the reduction of curtailment from local renewables, avoiding the use of high carbon technologies, and peak demand reduction were used in the categorisation. Further details on the financial savings and other benefits from V2G are given in Appendix 10.3.

We assessed the V2G opportunities in the context of the Scottish fleet’s size and respective emissions. We ranked the opportunities to highlight the potential decarbonisation potential from V2G. Figure 29 shows a breakdown of Scottish road transport emissions in 2021, with passenger cars accounting for the majority of vehicle emissions in Scotland at 53.3%, followed by HGVs at 20.6%, LGVs at 20.2%, buses and coaches at 1.2%. Furthermore, in 2021 Scottish road transport fleet was mostly comprised of passenger cars (84.5%) with LGVs at 10.6%, HGVs at 1.2% as shown in Figure 29.

(a)	(b)

Furthermore, most vehicles across all vehicle types are operated in an urban local environment, particularly passenger cars and buses (Figure 30).

Figure 30: Breakdown of registered vehicles split by urban, rural, and mixed environments. Urban, rural and mixed classifications were allocated based on the number of registered vehicles within a given council [64] and the urban-rural population split for each council [65]. ^[8]

Financial benefits

V2G can create financial savings for customers through participation in flexibility services, energy arbitrage, and minimising grid electricity consumption through the utilisation of on-site renewable generation.

From the research on V2G trials outlined in Section 10.2 there is a significant emphasis placed on Frequency Response, which is made up of several products including Dynamic Containment, as a key V2G benefit. However this neglects considerations of technical and metering barriers in products like Dynamic Containment. The most significant V2G advantages will likely come from the combination of services, such as energy arbitrage with integration of on-site renewable energy sources.

Energy arbitrage

Energy arbitrage generates financial value by capitalising on fluctuations in energy prices. V2G can be used to sell electricity (discharge) back to the grid during periods of high prices and to buy electricity (charge) when prices are lower. Energy markets operate on a national (Great Britain) level, meaning that there isn’t a distinct market solely for Scotland. Energy trading is conducted by suppliers, who can pass on the benefits to consumers through tariffs, including export tariffs and time-of-use tariffs. A current example of this is the ‘Agile Octopus’ offered by Octopus energy [66]. This pricing mechanism changes every half hour based on wholesale electricity processes and aims to reduce demand when electricity prices are high.

Flexibility services

V2G can also generate financial value by participating in flexibility services which provide system benefits, such as frequency response and constraint management. In Scotland, flexibility services are particularly focused on the constraints in the transmission network at the Scotland-England border [67]. Scotland’s high renewable potential can exceed the network capacity, resulting in constraint costs caused by curtailment. In FY23, this cost amounted to £344 million, representing 8% of the total expenses required to operate the network and one of National Grid ESO’s (ESO) greatest expenditures in the year [68]. The ESO has two key tools to mitigate the need to curtail renewable generation in Scotland:

1. The Balancing Mechanism is the primary tool for addressing constraints on the Scotland-England border. Assets are dispatched in real-time to adjust demand or generation, thereby maximising the penetration of Scottish renewables. This presents an opportunity for Scottish V2G, as many customers could be paid to charge or discharge their EVs.
2. The Local Constraint Market is a new ESO market currently being trialled to help manage network constraints at the Scotland-England border. The service aims to involve domestic and commercial consumers in constraint management, offering a demand turn-up service for those unable to access the Balancing Mechanism. This is based on stringent metering requirements of the Balancing Mechanism which are not fulfilled by most domestic charge points. It is important to note that participation in this service cannot be stacked with other services, as it serves as an “entry level” flexibility product.

Constraint Managed Zones

Additionally, both Scottish distribution network operators, Scottish & Southern Electricity Networks and Scottish Power Energy Networks oversee a number of Constraint Managed Zones, where they procure local flexibility services to alleviate or defer network upgrades, as shown in Figure 31. These zones are distributed across urban areas like Edinburgh and Dundee, rural regions such as the Highlands, and islands including Arran, Lewis, and Harris. V2G can provide these services by discharging energy into the local grid when dispatched by SSEN or SPEN. As the adoption of electric heating and electric vehicles accelerates in Scotland, the need for CMZs is expected to grow, and their financial value can be particularly high in areas where network upgrades are costly, such as urban or remote locations.

Figure 31: Illustrative mapping of Constraint Managed Zones for SPEN [69]. The orange circles indicate the locations of the CMZs within the network operated under SPEN – note: locations are illustrative and do not show precise areas.

System benefits

V2G technology could be used to relieve grid congestion during periods of high renewable energy production and at times of peak demand from consumers. This reduces carbon emissions by avoiding the utilisation of high-carbon technologies such as gas power plants for grid balancing, as described in Table 7.

The ESO anticipates that V2G will play a significant role in providing power system flexibility, although this transformation may not be fully realised until after 2030 [70]. The delay is primarily attributed to the time it takes for the benefits of V2G to outweigh the system costs. Table 8 outlines the projected increases in system peak demand in Scotland from 2025 to 2050. V2G is projected to reduce the system’s peak demand by 1% in 2030, reaching 12% reduction by 2050 from increased uptake of EVs. Figure 32 shows the system peak reduction in terms of GW from 2025 to 2030, which levels off at 1.4 GW beyond 2040.

Figure 32: The potential for V2G to reduce peak electricity demand in Scotland in terms of system peak reduction from 2025-2050.

Carbon benefits

V2G can lower grid carbon emissions by reducing curtailment and use of high carbon technologies for flexibility services or at times of peak demand. For instance, a study conducted in the UK in 2021 [41] estimated that the introduction of 50,000 V2G-enabled electric vehicles between 2025 and 2030 could reduce annual CO₂ emissions by approximately 60 tCO₂e per year in the UK, primarily by preventing the curtailment of renewable output, especially wind generation. Further carbon emissions savings have been identified in the literature, notably 63 ktCO₂e of expected annual emissions avoided in the UK from the utilisation of approximately 30 MW of V2G capacity [71]. These carbon emissions savings are expected through the utilisation of EVs to provide fast response to deliver grid services, reducing the use of carbon-intensive gas plants.

Review of costs associated with V2G

V2G requires additional hardware and power electronics to enable the bidirectional flow of electricity between the EV battery and the grid, for both alternating current (AC) and direct current (DC) technologies. Presently, DC V2G chargers are significantly more expensive than smart chargers, but costs are expected to decrease with increased manufacturing volumes and technological advancements. AC V2G is expected to be lower cost than DC but still more expensive than smart chargers [72]. Although maintenance cost is typically low for all chargers, it may rise to approximately £100 per year per charger (£ 2023) for general repairs for more complex V2G hardware [73]. Also, although it is uncertain (and discussed in more detail in Section 10.4.2, we expect V2G to lead to more rapid battery degradation [13]. This may incur ongoing costs, even if covered by car warranties. These cost factors influence the viability of V2G use cases and explored further in the following sections.

Hardware and installation

The high costs associated with DC bidirectional chargers stem from the need for both a DC charger and a grid-tied inverter. Both components use power electronics similar to those used in solar PV inverters. Previous analysis used projected costs of PV inverters to project the falling price premium of DC V2G chargers, modelling a 67% fall in price between 2023 and 2030 [74].

Although AC V2G is currently in trial stages and the precise cost of its hardware remains uncertain, AC bidirectional chargers are anticipated to be significantly less expensive than DC. AC V2G hardware manufacturers, such as Sono Motors [72], estimated that the hardware premium for AC bidirectional chargers would be approximately 70% lower than that of DC bidirectional chargers, which can be estimated as an additional cost (premium) of £948 in 2023 [72]. Nevertheless, the costs for installing an AC V2G charger are expected to remain more costly than those for a standard AC smart charger, primarily due to the more intricate controlled rectifiers required to facilitate bidirectional power flow [75].

The cost reduction projections [74] were updated considering the 2023 estimation of the cost premium for DC and AC chargers, with “premium” meaning the additional cost beyond that of a smart charger (Figure 33). The high and low cost scenarios are explained in Section 11.5.3.

Figure 33: Cost premium (£ 2023) of a V2G charger above that of a 7.2 kW unidirectional smart charger, for both a low and high scenario. These scenarios are calculated from available data in the literature [74, 76, 72].

Literature has suggested that the costs roughly scale with the rated power of the charger [74, 77, 75], although the relationship may not be perfectly linear [75]. These considerations highlight the complexities of V2G charger costs.

Battery degradation

A comprehensive literature review on battery degradation in EVs was conducted, using recently published research and real-world data.

There are two forms of battery degradation to consider:

• Cycling degradation: battery capacity gradually diminishes with each charge/discharge cycle, signifying that the more cycles a battery undergoes, the greater its degradation [13].
• Calendar degradation: battery capacity can fade over time, particularly when the battery is left at extreme states of charge (0% or 100% SOC) [14].

Real-world data obtained from Geotab suggests that EV batteries degrade by approximately 0.04% of their state of health per discharge cycle [78]. However, this discharge rate includes both cycling and calendar degradation. Further research has been conducted with the aim of distinguishing the effects of cycling and calendar degradation on battery state of health. Research from the Technical University of Denmark suggests that cycling degradation alone leads to approximately 0.005% state of health (SOH) reduction per discharge cycle [79].

Two scenarios were modelled to represent the cost of increased battery degradation as a result of V2G, expressed as a cost per MWh discharge. The high scenario is based on the Geotab data [78] and the low scenario assumes that increased degradation from V2G is solely from cycling degradation [79]. The modelling is shown in Figure 34, and indicates the high uncertainty (77%) in the impact of battery degradation on the V2G use case.

Figure 34: Cost of battery degradation (£ 2023) due to V2G used in modelling for low and high scenarios. To calculate these scenarios, two degradation rates were found in the literature [79, 78] and applied to Bloomberg battery pack cost projections [80].

Stakeholder engagement

The project included three stakeholder engagement sessions related to the identified use cases. The stakeholder engagement sessions involved discussion of key topics, including:

• Typical duty cycles of the fleet
• Electric models within the fleet, past or planned electrification experience and electric charging infrastructure
• Opportunities and barriers to V2G, including any past experience

The list of stakeholders and relevant vehicle types discussed during the session are given in Table 9.

Appendix: Detailed modelling method

Key data sources

Key data sources have been included in Table 10. These were used as a basis to begin the literature review process.

Method breakdown

The project was separated into 5 tasks which are described in Table 11. The first two tasks involved a literature review to understand the current V2G market, looking at findings from V2G trials and associated costs from V2G. From this process, opportunities for V2G were identified and ranked according to their impact. Task 4 explored the additional value for V2G with respect to use cases chosen from the list of opportunities. Finally, Task 5 involved the generation of this report providing the assessment of the potential for V2G to accelerate the decarbonisation of road transport in Scotland.

Key definitions

Opportunities have been categorised by vehicle type utilising V2G, daily operation, charging window, local environment, and geographic context. Once opportunities were identified, sources of financial savings were outlined. Additionally, non-financial advantages related to V2G, such as positive impacts on the electricity grid, were identified and clarified. Descriptions for these terms are provided in Table 12.

Potential carbon emissions reductions from a fully electrified fleet

The potential carbon savings from a fully electrified fleet were calculated assuming an instantaneous switch from fossil fuel vehicles to electric vehicles for passenger cars, LGVs, buses, HGVs and RCVs. The emissions from charging a fully electrified fleet were calculated using the equation below:

These emissions were then compared to the carbon emissions for a fossil fuel-based fleet using the Scottish total road transport emissions in 2021 and the percentage breakdown per vehicle type [2]. The assumed inputs for the calculations are given in Table 13.

There was no identified data on emissions RCVs in Scotland. To calculate emissions reduction potential, the current UK emissions from RCVs in 2020 [16], the percentage of RCVs in Scotland in 2020 [17] and the percentage of RCVs in Scotland in 2020 [17] were used as shown in Table 13. To determine the emissions reduction potential, the emissions reduction from the use of 1 electric RCV relative to that of a fossil fuel RCV was used [83] and scaled to the number of RCVs within the Scottish fleet.

Use case modelling

Duty cycle assumptions

Modelling of additional value

Each of the five use cases charging profiles were modelled to understand the value of participating in a number of flexibility services. The flexibility services considered, and the source of the data used is summarised in Table 15.

The charge and discharge profiles of each use case was optimised on a half hourly basis over 24 hours. Modelling considered the size of the vehicle’s battery in addition to its daily charging demand, to ensure sufficient charge for the daily operation of each use case within the allocated charging window and that the state of charge of the battery remains at least 40% to limit battery degradation and ensure sufficient range if charging window was unexpectedly shortened. The vehicle characteristics of each use case are summarised in Table 16, alongside sources for each. The additional value was calculated in 2025 and 2030 according to the different vehicle characteristics but was assumed to remain constant over the 15-year lifetime of the V2G hardware in the cash flow modelling.

Cost modelling

A high and low-cost scenario was defined for the use case modelling, considering the costs identified in Appendix 10.4. The cost scenarios are summarised in Table 17.

The hardware and installation costs are calculated considering the cost premium as set out in Table 17 considering the modelled charger power for each use case. The total cost premium of V2G hardware and installation for each use case is shown in Table 18.

The cash flow modelling considers the additional degradation as a result of V2G participation and does not calculate the total degradation of each vehicle’s battery including the impact of driving. The modelled annual degradation cost from V2G across low and high scenarios for each use case is shown in Figure 35.

Figure 35: Modelled annual degradation from V2G across low and high scenarios for each use case.

Cash flow modelling

The use case for the selected use cases was assessed through a simple cash flow modelling comparing the additional value and the costs, as described above. The cash flow was modelled over the assumed 15-year lifetime of the hardware [12] and assumed a 3.5% discount rate [90].

The cash flow is calculated for each of the selected use cases assuming the solution is installed in 2025 or in 2030. The cash flow assumes the annual additional value remains constant over the lifetime of the solution.

© Published by ERM, 2023 on behalf of ClimateXChange. All rights reserved.

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

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

1. 
   

   The total volume of Scottish Transport emissions remains lower than it was in 2019, pre-pandemic. ↑

   
   
2. 
   

   The emissions from RCVs were estimated using the total emissions from RCVs in the UK and the estimated percentage of RCVs in registered in Scotland [16, 31] ↑

   
   
3. 
   

   Calculated from the total road transport emissions and the percentage from passenger cars [2]. Emissions savings are determined assuming the entire fleet is electrified and charges using a grid intensity of 26.9 gCO₂/kWh [84]. ↑

   
   
4. 
   

   Calculated from the total road transport emissions and the percentage from LGVs [2]. Emissions savings are determined assuming the entire fleet is electrified and charges using a grid intensity of 26.9 gCO₂/kWh [84]. ↑

   
   
5. 
   

   Calculated from the total road transport emissions and the percentage from HGVs [2]. Emissions savings are determined assuming the entire fleet is electrified and charges using a grid intensity of 26.9 gCO₂/kWh [84]. ↑

   
   
6. 
   

   Calculated from the total road transport emissions and the percentage from buses [2]. Emissions savings are determined assuming the entire fleet is electrified and charges using a grid intensity of 26.9 gCO₂/kWh [84]. ↑

   
   
7. 
   

   Calculated from the total road transport emissions from RCVs in the UK [16] and determined in Scotland by the percentage of RCVs located in Scotland [17]. Emissions savings are determined assuming the entire fleet is electrified and charges using a grid intensity of 26.9 gCO₂/kWh [84]. ↑

   
   
8. 
   

   “Urban” councils have over 50% of their population in “large urban” or “other urban” locations, “Rural” councils have over 50% outside “large urban” or “other urban” locations, and “Mixed” councils have almost equal splits in both urban and rural locations. ↑

   
   
9. 
   

   Sources: average daily mileage [19], battery size, electricity consumption and charger power [21]. ↑

   
   
10. 
    

    Sources: average daily mileage [19], battery size, electricity consumption and charger power [21]. ↑

    
    
11. 
    

    Sources: average daily mileage [19], battery size, electricity consumption and charger power [88]. ↑

    
    
12. 
    

    Sources: average daily mileage [19], battery size, electricity consumption [88] and charger power [89]. ↑

    
    
13. 
    

    Sources: average daily mileage [22], battery size, electricity consumption and charger power [23]. ↑

    
    

The Carbon Neutral Islands project is a Scottish Government commitment to support six Scottish islands (Islay, Raasay, Hoy, Yell, Barra and Great Cumbrae) to become carbon neutral by 2040.

This report presents evidence on the readiness status of island businesses to meet this challenge.

Its focus is on the skills available within business to support decarbonisation, skills gaps and future requirements.

The research included a literature review along with online surveys and in-person interviews with key stakeholders on the islands.

Findings

• While most of the businesses interviewed across the six islands are willing and ready to engage with the Carbon Neutral Islands project, there is a lack of knowledge and skills.
• A minority of businesses actively track their carbon footprints. However, some businesses who are developing a strategic plan for decarbonisation do not always use their carbon footprints to guide their strategies.
• Time and cost are key barriers to businesses in tracking carbon footprints and developing a decarbonisation strategy. While most agreed that tracking carbon footprints and developing plans are important, half or more of the businesses in the renewable energy sector, agriculture, housing and trades sectors did not do this.
• Participants have a general understanding about carbon use in their businesses and a general awareness of how to measure it via calculator tools. However, most participants were less confident in their technical knowledge and how to implement changes. There are challenges around finding footprint calculators relevant to individual island-based businesses and guidance for plan development.
• There is a general lack of knowledge of the skills that are required for decarbonising businesses and how to develop these skills. Other key gaps include a lack of understanding of the technical options for decarbonisation. Our evidence indicates that agriculture, aquaculture and marine, the self-employed and logistics sectors require the most support over a wide range of skills.
• Current actions towards carbon neutrality are short term and generalised, such as selecting 2-year green energy tariffs. Barriers to longer-term carbon neutrality include costs of green technologies and a lack of qualified technicians within the islands for installing or maintaining equipment (e.g. heat pumps and solar panels).

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

December 2023

DOI: http://dx.doi.org/10.7488/era/3885

Executive summary

The Carbon Neutral Islands project is a Scottish Government commitment to support six Scottish islands (Islay, Raasay, Hoy, Yell, Barra and Great Cumbrae) to become carbon neutral by 2040.

We present evidence on the readiness status of island businesses to meet this challenge. Our focus is on the skills available within business to support decarbonisation, skills gaps and future requirements. Our research included a literature review along with online surveys and in-person interviews with key stakeholders on the islands.

Findings

• While most of the businesses interviewed across the six islands are willing and ready to engage with the Carbon Neutral Islands project, there is a lack of knowledge and skills.
• A minority of businesses actively track their carbon footprints. However, some businesses who are developing a strategic plan for decarbonisation do not always use their carbon footprints to guide their strategies.
• Time and cost are key barriers to businesses in tracking carbon footprints and developing a decarbonisation strategy. While most agreed that tracking carbon footprints and developing plans are important, half or more of the businesses in the renewable energy sector, agriculture, housing and trades sectors did not do this.
• Participants have a general understanding about carbon use in their businesses and a general awareness of how to measure it via calculator tools. However, most participants were less confident in their technical knowledge and how to implement changes. There are challenges around finding footprint calculators relevant to individual island-based businesses and guidance for plan development.
• There is a general lack of knowledge of the skills that are required for decarbonising businesses and how to develop these skills. Other key gaps include a lack of understanding of the technical options for decarbonisation. Our evidence indicates that agriculture, aquaculture and marine, the self-employed and logistics sectors require the most support over a wide range of skills.
• Current actions towards carbon neutrality are short term and generalised, such as selecting 2-year green energy tariffs. Barriers to longer-term carbon neutrality include costs of green technologies and a lack of qualified technicians within the islands for installing or maintaining equipment (e.g. heat pumps and solar panels).

Next steps

Our findings aim to support areas of possible action for consideration by the Carbon Neutral Islands (CNI) project team and appropriate Government agencies. The following steps would help address the skill gaps identified and support island businesses to decarbonise:

• Develop a training programme for the CNI project Community Development Officers (CDOs) to enable them to provide island businesses with information resources and support knowledge and understanding. They could directly support businesses in the production of carbon actions plans. Since the production of this report, CDOs across all of the islands have undergone training including accredited qualifications in corporate standard carbon accounting, energy assessor training and other energy efficiency advisory training. It has been hugely valuable for the CDOs and the communities they serve. Roll out to other islands would significantly benefit them.
• Develop island specific carbon planning tools such as carbon calculators. These should ensure relevant measures to each island and account for sectorial differences within each community.
• Provide training for technicians, electricians, mechanics and other trades so they can provide installation and maintenance services to green technologies.
• Develop sector specific roadmaps to carbon neutrality with short- and long-term targets, which aim to address key barriers identified in this report.
• Run specific agricultural focused actions such as additional skills development support for crofters and small farms to understand and implement sustainable land management practises and conduct carbon audits, which are critical for securing some grants and funding.
• Develop a coordinated support package for islands businesses with relevant government agencies and training providers. The level of support for businesses on Cumbrae has increased substantially to include Commercial EPCs, Display Energy Certificates, Carbon Audits and Businesses Energy Scotland funding support. There would be significant benefits to replicating this across the other islands.
• Upgrade energy infrastructure in islands, to support the inclusion of greener technologies as part of businesses decarbonisation strategies.
• Promote a circular economy, which would support reduction in waste and supply chain carbon emissions, aiding in businesses achieving net zero.

Glossary

Introduction

The Carbon Neutral Islands (CNI) project is a Scottish Government ‘programme for government’ commitment to support six Scottish islands (Islay, Raasay, Hoy, Yell, Barra, and Great Cumbrae) to become carbon neutral by 2040. It also aims to support other goals such as economic and skills development.

This project investigates the extent to which businesses, public sector organisations and other bodies within key sectors across the six islands have carbon neutral strategies. Sectors of interest include tourism, food & drink, retail, leisure, transport, aquaculture and marine, renewable energy, agriculture, media, self-employed, logistics, housing and construction/trades. We investigate what would be needed in order for businesses to adopt and implement a carbon neutral strategy.

We consider the skills required in order to deliver carbon neutrality in these sectors on the six Scottish islands. We also consider the nature and scale of the overall skills development that is required to help island businesses meet the goals of the CNI project, both in the medium term (to 2030) and longer term (to 2040). The key challenges and barriers, including sector-specific barriers, for island businesses in preparing to meet the goals of the Carbon Neutral Islands project are reviewed.

We undertook desk-based literature reviews on current sector readiness on a UK-wide scale and a review of local, Scottish and UK policy and how it supports island businesses. We used online surveys in an attempt to achieve broad participation across the six islands. In addition we visited the islands and conducted in-person interviews. A detailed methodology can be viewed in Appendix 1.

Key challenges we experienced undertaking this project were:

• Securing participation – Out of approximately 600 businesses identified and contacted through desk-based research, only 63 surveys were returned with an additional 29 interviews conducted across the six islands.
• Statistical analysis – due to the limited responses, detailed sectorial analysis was not possible. In some cases there were only 2 responders for a sector. Out of the 13 participating sectors, only 4 sectors had over 10 responders (see Table 1 – Error! Reference source not found.).
• There are a number of crossovers between sectors where a business is linked to a number of sectors such as tourism, retail and food. This makes statistical analysis between sectors more challenging because the distinction between them is unclear. This is reflected in the sector breakdown tables, where although there were 59 responders with 6 choosing not to answer, a number of responders selected multiple sectors their business fell into. There were also responders who operated more than one business and used the same survey to answer for all the businesses they operated. This increased the total number of sectors who responded to the questions from the expected 63 to 122. This makes comparisons difficult and potentially skewed data.

As a result, we were unable to present the level of robust findings that may have been possible with more substantial response rates. However, we are confident that the 10% sample achieved, combined with the in-person interviews and input from CDOs, means that we have representative evidence to support our findings.

We can’t conclude on any substantial differences in the readiness and skills between some sectors as the response rate was insufficient.

Overview of island businesses

We found the following sector profiles within the islands:

• Tourism is a dominant sector across all islands (both within the CNI target islands and amongst the other UK islands more generally). This extends to supporting industries such as hospitality and distilleries.
• Independent trades are a vital sector on islands including construction and mechanical, however few have a significant online presence, meaning it was difficult to obtain accurate numbers of these businesses.
• Retail is a prevalent sector with most falling into the food and drink category. Local grocery stores often have a multipurpose function offering post offices and parcel pick up points, some gifts and locally produced goods. Dedicated retail shops are limited on the islands with smaller resident populations such as Hoy and Raasay, however larger population islands such as Cumbrae and Islay have a more diverse retail sector.
• Agriculture and aquaculture are also important sectors across the islands for economic revenue and employment, although not as large in number of businesses and scale of operations compared with rural and coastal mainland areas.
• Large commercial farms are less common on islands than on the mainland. However, there are a larger number of crofts located within the islands, owned by small holders who do not sell to larger supply chains and are more invested in selling goods/produce locally in small volumes or for private consumption.
• There have been challenges for aquaculture businesses such as restricted access to markets following Brexit and losses during the Covid-19 pandemic, meaning there has been a downturn in shellfish and the wider fishing industries.

Figure 1 shows the breakdown of the number of businesses identified across all the CNI islands. While each island showed a diverse range of businesses and were unique in many sector distributions, there was a significance of tourism and recreation businesses across all six islands. These industries include bed and breakfasts, hotels and other holiday accommodation, shops, grocers, galleries, cafés and theatres. Other sector businesses have a critical value to the islands e.g. aquaculture and agriculture can employ a considerable number of staff though there are few businesses. The transport sector reflects the size of the communities, with smaller populations having fewer transport businesses. Some island business operate several operations from a single main business (i.e. a farm may also be a B&B, or a bus operator may also be a mechanic etc.) which makes accurately calculating the numbers of businesses challenging.

Assessment of carbon neutral strategies across island businesses

Carbon reduction readiness

There were 63 responses to surveys and in person interviews. Full details and breakdown of responses can be found in Appendix B (Section 12.5). We found that around half of participants were aware of their businesses carbon footprint to some degree with less than 20% actively tracking it. Around 25% of participants have or are developing a decarbonisation strategy.

Most businesses do not currently track their carbon footprint. More businesses in the tourism, media and transport sectors actively track their carbon footprints than in the other sectors. However, the percentage of businesses in these three sectors actively tracking their carbon footprint is still under 50%.

Similarly, the majority of businesses regardless of sector are not currently producing carbon reduction plans. Those businesses that are tracking their carbon footprints are more likely to produce decarbonisation plans.

Barriers to developing a carbon strategy

Participants were asked about barriers to tracking their carbon footprints and developing a plan to decarbonise.

Summary of overall responses

The majority (69-70%) said they did not have time to produce carbon footprint baselines. There was also some confusion and lack of understanding on how to do this and which tool out of the many options was right for them. There were also some issues raised with the appropriateness of standard carbon assessment metrics to island business, particularly farming. There is no clear advice on carbon recording tools, calculators and other baseline production options and explanation of how they differ, and which would be most appropriate for islands businesses. This complexity further dissuades businesses from looking into calculating their carbon footprint.

Responders stated that it would be helpful to outsource the carbon footprint and plan production. However, it is difficult to find and apply for the limited funding available for this. We understand that Highlands and Islands Enterprise are aware of this issue and are investigating the support they, or other agencies, could offer.

Responders stated that access to training and external support would be beneficial to allow business owners and operators to better prepare for a net zero transition. However, finding time for upskilling remains a key barrier.

Summary of sector analysis

Time and costs are the most common barriers to businesses in tracking carbon footprints and developing decarbonisation strategies. Most acknowledged that developing footprints and plans were important, but:

• 67% of businesses in the renewable energy sector indicated that developing a footprint was not a priority for their business. Half of businesses in other sectors including agriculture, housing and trades businesses also stated this was not a priority.
• Renewable energy sector place higher priority on developing a plan, with only 25% stating this was not a priority. We find that this sector puts more value in producing the plans than tracking footprints.
• Retail businesses indicated they placed more value in creating a footprint than a plan, as did logistics and leisure.

Prioritising internal resources for decarbonisation efforts is indicated to be challenging across all sectors with the third most identified barrier being the lack of skills and support needed to produce a carbon footprint or plan. Further detail is provided in Appendix B.

Overall Carbon Neutral Island barriers to developing a carbon strategy

Developing a decarbonisation plan is a complicated undertaking, requiring financial and supply records to provide a carbon footprint baseline and develop future actions to improve the carbon footprint. This can be a complex task with many businesses saying that they do not have the knowledge on how to create a baseline or where to find appropriate information to assist them.

Most businesses on the islands are micro scale (up to 10 employees), with many being sole ownership and minimal staff with seasonal increases. Larger businesses (still within SME definitions) are found on some of the larger islands such as Islay, Barra and Yell specifically within distilleries and Aquaculture industries. Producing a plan and looking for alternative options to reduce the carbon emissions is difficult for these businesses due to time pressures within the business.

Costs are also a large factor in preventing businesses being enabled to decarbonise, with many green technologies and alternatives remaining at a higher purchase cost than non-green options. A common example are EVs, while significantly more accessible now than 5 years ago, the purchase costs are still higher than equivalent combustion engine cars, with the investment return taking serval years to see the financial benefit. In contrast, from discussions with businesses owners we found that new clean heating systems can be a worthwhile investment. Although purchase prices may be higher, the overall running costs are lower compared to the high cost of oil which is the main source of heating in the islands, the investment can have favourable returns in a short period of time.

These barriers make it difficult to produce a decarbonisation strategy even though around 70% of participants would like to make it more of a priority.

Assessment of business readiness

We reviewed the details of island business readiness to become carbon neutral. Full details from the surveys can be found in Appendix B (Section 0). While formal decarbonisation plans were in place for a minority of business sectors, most responders reported that they are actively taking steps to reduce their carbon use. The findings suggested that the number of employees (size of business) did not factor into decarbonisation strategies or readiness. There were some sectoral differences however, with businesses like distilleries, fish farms and agricultural businesses having a more developed carbon strategy, this is due to a necessity to either comply with operational conditions or access subsidies.

The majority of the participants indicated that they were taking some steps to becoming net zero ready. However, the largest proportion (87%) said that the action was recycling. This action alone is not sufficient to meet net zero targets. We found that other actions were high level such as reducing paper/plastic use, short term such as a 2 year green tariff and generalised with non-industry-specific actions. There are limited long term technical actions being planned or undertaken by individual businesses due to costs and lack of qualified technicians such as solar panel installers within the islands to construct and maintain the green technology equipment.

Recycling is the most common action taken by businesses to reduce their carbon footprint and conserve resources. The circular economy is important among island businesses and participants stated that they try to reuse and maintain resources due to limited access or costly waste disposal. There are added ferry costs for waste removal or recycling, with some smaller islands having a reduced recycling capability, with recycling centres often at capacity restricting further use.

A reduction in business travel has been as a result of move to IT based solutions nationally following Covid-19. Some of the more expensive decarbonisation options such as electric vehicles and micro energy generation are more of a challenge for relatively small island businesses.

We found from the in-person interviews that there is a strong desire within island businesses to support other local businesses and providers of goods to keep supply chains local. This is more challenging on smaller islands with more limited local products available to source.

While no formal decarbonisation plans may be in place for all business participants, most reported that they are actively taking steps to reduce their carbon use (Appendix B Section12.8). Of those that stated that they are not taking any steps to reduce their carbon footprint at this point, most are planning to do so in the future.

Key skills gaps

Overview of Carbon Neutral Islands businesses skill readiness and gaps

Having access to skills to understand how to reduce carbon emissions is essential to the net zero transition. All participants indicated they have a general ‘basic level’ understanding about carbon use in their businesses and stated they are aware of options to measure carbon use via calculator tools. However, when it came to technical knowledge and implementing changes, participants were less confident in their skills. Fewer than 1/3 of participants are confident in their technical knowledge to deliver technical and detailed decarbonisation actions (Figure 4).

Only 22% of responders have actively sought external training to increase their skills and understanding of carbon reduction, with those who did undertake training using online webinars and internet sources (Figure in Appendix B). Many of these online training sources did not result in accreditation or certification, however a small number pursued a deeper level of understanding and completed certified courses.

Skills gaps and barriers across CNI businesses

Participants were asked what challenges and barriers they faced in gaining the skills needed to develop actionable decarbonisation plans and achieve the transition to net zero by 2040. The following responses provide a guide on where further support could be focused to support CNI businesses.

The prominent responses were again cost and time, similar to business planning. This was followed by not having the skills to increase this knowledge suggesting there is a skills gap to be filled.

Sector skills readiness and gaps

Due to limited returns from some sectors it is difficult to do a comprehensive comparison of net zero readiness and skills between sectors, only four participating sectors had responses from more than 10 businesses. However, it is possible to draw evidence to support conclusions on the general level of readiness of islands businesses on the whole.

Summary of analysis

The analysis has highlighted that there are substantial gaps in the skills required to support the route decarbonisation across most of sectors. The main gaps across all sectors include the lack of knowledge of what skills are required to meet net zero. Most of the businesses we spoke with did not know what skills they required to begin to address the challenge, such as the skills needed to produce a carbon footprint or a decarbonisation plan.

Businesses are also unclear on how to access relevant skills, many having significant time restrictions limiting their ability to research the skills or to develop them within the business. Another key issue is the lack of financial support or prioritisation to pay for training or employ someone with this knowledge. We found evidence of a willingness to learn. Finding ways to signpost, fund and develop the relevant skills would be an important first step for policy makers. Developing these skills (see also Table 10 in Appendix B) within the islands would support the longer-term roll-out of decarbonisation plans across the island businesses. Within the CNI project (to 2040) there is the opportunity to create a skills development programme to drive the change required.

Current skills across different sectors

The majority of participants from 9 sectors out of 13 have indicated they do not know what skills are required to produce plans or deliver the actions within the plans (Table 7 in Appendix B). Those in renewable energy, housing, agriculture, and construction felt that they had a good understanding of skills requirements. Sectors such as renewables and housing have clear guidance on how to reduce carbon, hence a better understanding than most about what skills are required to plan for and action decarbonisation strategies.

While all sectors responded that they had a general understanding of carbon use within their business, only those working in the renewable energy sectors felt they had the technical knowledge and ability to understand and track carbon use within their business. This technical understanding makes it easier for these sectors to produce and implement plans to reduce carbon emissions. Our evidence suggests that there is a lack of the more specialist skills to implement carbon reduction actions across all sectors other than the renewables sector.

Few have undertaken training in carbon reduction skills, with the highest proportion of those who have had training within the renewable energy, aquaculture and transport sectors. Up to half of responders from these sectors stated they have actively sought training in these areas.

During interviews it was clear that although willing to learn, it was difficult to find the time or cost to be able to undertake training.

Skills gaps and barriers across sectors

We also asked about potential options to improve business readiness and understanding of the requirements to decarbonisation.

When it comes to developing skills to assist businesses in transitioning to net zero, it appears that there is a significant difference between the sectors in what skills they require to develop (although there were few participants for some sectors). Our evidence indicates that that agriculture, aquaculture and marine, the self-employed and logistics require the most support over a wide range of skills (Table 10 in Appendix B).

The main barrier identified by all businesses across all sectors to decarbonising was cost (Table 11 in Appendix B). Having time was also a key barrier for businesses in all sectors except transport and renewable energy.

Lack of funding features highly in the barriers and challenges businesses face in decarbonising, along with the cost of time. There are funding routes for some businesses, for example Transport Scotland offers grant funding to help organisations install electric vehicle (EV) charging infrastructure on their premises (Find Business Support.gov, 2024). There is also the Scottish Governments SME Loan Scheme (Business Energy Scotland.org, 2024), which is designed to help businesses install new energy efficient systems, equipment or building fabric improvements (loans available up to £100,000). However, the landscape can be confusing and complicated, poorly signposted with highly competitive application processes. Most of the schemes tend to be nationally focussed and rarely take into account island issues such as ferry journeys and limited technical support locally. Information access on decarbonisation strategy advisory services is also an important opportunity. If information was clearer and readily available, businesses would have more confidence in their understanding and the skills needed to investigate green and low carbon alternatives as well as being able to produce carbon baselines and reduction strategies.

Interview insights

These are the common challenges and opportunities raised by businesses through this research.

Opportunities:

• CDOs are a good resource – could they be trained to help produce plans?
• Training local trades in installation and maintenance
• Circular economy practices are important
• Land management important for businesses and communities in decarbonisation strategies

Challenges:

• Old building stock, hard and expensive to renovate/upgrade
• Infrastructure limitations for EVs and other green technologies
• Limited access to renewable and low carbon technologies
• Regulation restrictions hinder some effort, more flexibility through policy needed
• Decarbonisation plans for Agricultural businesses will be required for subsidy access, support not always available for small crofting and farms
• Lack of skills/knowledge to effectively strategize for transition – Toolkits/packs would be useful
• Wide scale dependency on oil for heating
• External supply chain carbon cost
• Lack of financial incentives/ expensive to decarbonise

Evaluation of challenges and barriers to CNI business net zero readiness

There were many common themes from the in-person interviews including: buildings; supply chains; agriculture; green technologies and infrastructure; and regulation and policy.

While not necessarily exclusive issues to island communities, these illustrate the particular challenges faced by island businesses. The significance and prevalence impact on the viability of implementing carbon downshifting within island based businesses. Each issue is explained further in the following sections.

Buildings

Older buildings, which are prevalent on the islands, face greater net zero challenges such as poor energy efficiency. This is due to buildings being poorly insulated, not having the capacity to have cavity wall insulation (stone built) and requiring extensive renovation to accommodate low carbon heating options. The ability to upgrade the older buildings is further exacerbated by the lack of trades able to do the renovations, cost of materials (these are significantly higher on Islands) and availability of materials as some suppliers do not offer carriage to some Scottish islands. This means that it is harder and more expensive to upgrade these buildings to be more energy efficient. While not solely a business challenge as this is an issue for residential buildings as well, many businesses are located within old buildings. This was made evident during the island visits and during conversations with the consultees and CDOs. A typical challenge for island buildings is the need to change heating systems. There are no mains gas lines on any Scottish island except one, Stornoway, which has a small gas network servicing a portion of houses in the main town. This limits common options to reduce cost and carbon with a switch from oil. While there are low carbon alternatives, these can be expensive to install such as electric heat pump systems which often require a whole system upgrade due to lower heating levels or require importing of fuel such as biomass which is costly and has a high carbon footprint due to transportation.

Supply chains

Island businesses have a larger supply chain carbon footprint than mainland Scotland counterparts due to additional transportation. While mainland businesses may find varied supplier access within their locality, island businesses are restricted by suppliers willing to ship to island locations and inevitably additional transport costs.

Agriculture

Businesses identified that it can be challenging to apply national policy in local island environments, such as livestock grazing practises in fields and land management practises. This can be counterproductive to low carbon ambitions. For example, waste management is a significant challenge to island farmers, while there may be a range of commercial waste management options for mainland farms, island farms have fewer options. Waste must be transported by island farmers on ferries to mainland agricultural waste facilities which is financially expensive, carbon intensive and time consuming. There is a need to identify ‘island proofed’ waste management practises or investment in island agri-waste facilities.

Some farming practices are not recognised in farming carbon audits such as not ploughing a field after harvest for reseeding. While it is widely acknowledged by interviewees that a more carbon efficient land management practice is needed, farmers are not able to record this as a “carbon positive” decision.

Green technologies and infrastructure

Green technology can be more expensive than conventional energy and transportation technologies but can be very efficient in an island setting (e.g. wind turbines due to a good wind resource). Businesses that do wish to invest in renewable technologies can find it difficult to find installers and to get prompt maintenance and repairs as they are reliant on mainland technicians who often view islands jobs as low priority and charge higher costs.

Local authorities across Scotland are seeking to install more EV chargers and some islanders would like more investment from their local authorities and other government organisations to ease the individual costs for charges and installation.

Grid capacity is a significant issue across the UK, and particularly so on islands where grid infrastructure is aged and under increasing constraint. While there is a strong desire to install microgeneration technologies such as solar and wind turbines, access to the grid is a challenge and also expensive.

Regulation and policy

While policy is a driving force behind net zero actions, for islands, policy and regulation can be a barrier for some businesses. By their nature, policy and regulations are uniform and broad reaching, not allowing for unique island characteristics. Regulations that may be appropriate for large and mainland businesses do not fully account for the differences of SME and island businesses. These UK and Scottish Government regulations can become barriers and restrict decarbonisation opportunities. An example raised by interviewees is the ability to utilise local produce and goods instead of having to import from large mainland suppliers. Regulation and policy does not allow the sale of locally produced food direct from the source. While it is understood the regulation is to ensure the quality and safety of food consumed, it is restrictive. Locally grown vegetables and fruit, eggs used to be a regular item on the shelves, supporting local farmers, crofters and other suppliers. Now, they are not allowed to buy direct from the grower and instead have to go through the larger distributor.

Another key restriction from regulation is the closure of island abattoirs due to regulatory cuts. The livestock must now be transported off island to be processed and returned back to the distributors. This increases costs for farmers, stress for the animals and increases the carbon footprint of the food products.

Evaluation of opportunities

Opportunities have been identified to assist businesses in achieving operational net zero by 2040. These opportunities include training; supply chains; and land management.

There are opportunities to help upskilling of business owners/operators as well as enabling them to utilise green technologies in their decarbonisation strategies. Each of these opportunities is explained further below:

Training

There are opportunities around training in various forms to aid in the net zero transition of island businesses. These opportunities would not only benefit the transition ambition, but also could increase island economic prosperity and could help reduce population decline often seen in smaller islands. Across many of the businesses and sectors that participated in this study, access to training and skills to understand and develop carbon footprints and decarbonisation plans was highlighted as important. A key finding is that there are opportunities to utilise the CDOs for the islands as contacts and signposters for training and support.

Training for island technicians, electricians, mechanics and other trades to install and service low-carbon technologies such as heat pumps, wind turbines, insulation and property retrofit would be beneficial to allow greater access to green technologies. Increased training for green technology skills would also benefit the island economy by attracting new businesses and skilled employees to the island. Currently islands are more likely to be reliant on Scottish mainland-based company support for green technologies, reducing reliability and efficiency of support and delivery of new technology, as well as adding to cost.

Supply chains

Island businesses in most cases will strive to support other local businesses, sourcing goods where possible within the island. While there can be significant challenges around local supply chains, there are also opportunities to increase local production. For example, ‘added value’ food production, with crofters, farmers and bakers able to develop new products from ‘home and locally grown’ produce. However, this can also have a negative implication for carbon emissions. For example, distillers interviewed on Islay mentioned the recent trend of local growing of barley products for whisky production results in higher emissions from the smaller scale cultivation of the crop and transportation of fertiliser and seed to the island at high cost and high carbon footprint, compared to buying ready produced barley grain from a bulk distributor.

However, restrictions from Food Standards Scotland regulation prohibit the sale of local produce with many providers not having sufficient accreditations or certificates to sell their goods commercially despite having a good food and health standard. This impacts on the businesses ability to reduce carbon emission from their supply chains as part of their CNI net zero readiness. Reviewing Food Standards Scotland agency regulations for small food growers to consider allowing more access to local sellers would support the local economy, reduce carbon footprint of imported foods as well as tackle some food insecurity issues unique to islands. This includes issues such as disruption to ferry transport essential to food delivery regularly during adverse weather events. Costs, food has a significantly higher cost than on mainland Scottland due to increase transport costs being added to the consumer price. Quality and storage ability can also be affected due to longer transportation times, this is prevalent with fruit, vegetables and eggs. Access to locally produced goods would have many benefits to ease food insecurity and improve economic development opportunities for Scottish islands.

The closure of most island abattoirs has seen increased costs for farmers and higher carbon footprints for the product being exported and imported back to the island. The Food Standards Scotland abattoir database (Food Standards Scotland, 2024) lists only authorised slaughterhouses and processing plants located on Barra, Isle of Lewis, Isle of Mull, and Islay. The slaughterhouse in North Uist is scheduled to close later this year. Orkney lost its abattoir in 2018/2019. With 93 inhabited Scottish islands, this is a significant deficit to local communities. Re-opening these facilities would likely be a financial and regulatory challenge. However, there could have significant carbon and financial benefits to farmers, increase animal welfare and reduce costs to island consumers as well as offering additional employment opportunities to island communities.

Land management

Good land management is well known for carbon storage and ecosystem services benefits. There is an opportunity to train and promote large landowner businesses, such as estate owners who operate shooting and fishing activities and farmers in alternative land management practises. Providing access to knowledge and skills could reduce the loss of carbon from standard practises such as ploughing, heath burning and over grazing. Further investment into island peat restoration would provide a useful carbon sink as well as offering more sustainable peat harvesting opportunities for businesses such as distilleries.

Conclusions

The ambition of the CNI project is for the six target islands to reach net zero by 2040, 10 years ahead of the UK target and 5 years ahead of Scotland as a whole. We focused on primary data collection through direct engagement with island businesses. This was enabled through direct involvement of the island-based Community Development Officers.

Overall island businesses are very willing to embrace the challenge to achieve carbon neutrality. They can see the benefits to them and the wider community and have a desire to engage and make progress. However, the challenges they face are significant and evidenced to be arguably greater than businesses based in mainland Scotland communities. The key message businesses conveyed through the interviews was having the ability to have island-focused solutions. This was enhanced by the overall support articulated for the CNI programme and in particular the CDO resource. There is a desire to enable further action through CDOs.

Our findings on three main research questions are as follows:

Do businesses have a carbon reduction plan or strategy?

Many businesses across all sectors have a desire to track their carbon footprints and develop decarbonisation plans. We found that there are significant barriers to acting on this desire. Cost and time are the most commonly identified barriers among island businesses. Skills and access to information are also a concern and a significant gap to enabling decarbonisation measures by businesses.

Do businesses have the skills to develop the carbon awareness and implementation of decarbonisation strategies?

The research identified that most businesses feel they lack specialist knowledge. Despite this, participants feel they have a good general understanding around carbon emissions in their business operations. They were keen to explore ways to reduce carbon but lack knowledge of how.

Significant gaps in the current skills across most SME island businesses included technical aspects on how to actively reduce emissions. There were also gaps in understanding suitability of green technologies and accessing information and funding to action decarbonisation initiatives.

Access to advice and the ability to develop skills in-house would be a significant benefit to many businesses.

What is required to support businesses to transition?

Key opportunities to close the skills gap and assist in the transition process are:

• Training local CNI CDOs to directly support the business community in accessing information and support to develop decarbonisation strategies. This could be via signposting to online resources or helping to develop a template decarbonisation plan for businesses to follow. Local representation is central to the decarbonisation efforts as they understand the unique nature of each island. There is a significant opportunity which could be progressed with HIE to sustain the role of CDOs and potential for income associated with fees for services provided, as HIE have provided funding for island CDOs previously.
• Training local trades in the installation and maintenance of green technologies is an opportunity to increase access to low-carbon alternatives as well as to open new economic opportunities for local supply chains. There is potential to establish a pan-island CNI trades network, enabled through CDOs, for sharing knowledge and resources.
• Many businesses are taking positive steps to reduce their carbon footprints and sustainable use of materials by utilising local supplies and services where possible. Increasing access to local services, skills and goods can significantly reduce carbon costs from external supply chains. Currently, islands are heavily reliant on external supply chains with larger carbon footprints and additional carbon from transportation. They also suffer from limited local purchasing options. This dependence on distant suppliers and supply chain insecurity is a unique feature of island business operation as well as general island living. Whilst there is unlikely to be a solution to this distance from market, there could be further attention given to procurement policy and support mechanism interventions which recognise these supply chain constraints for islands. Directly supporting and enabling the development of local supply chain and circular economy options would be beneficial as well as facilitating the pathway to net zero for islands.

Key recommendations

This section presents actions that could be taken to address the issues raised in our research.

Development of skills across the CNI sectors

There are opportunities around training in various forms to aid in the net zero transition of island businesses. These opportunities would not only benefit the transition ambition but could also improve island economic prosperity and reduce population decline often experienced on smaller islands.

Develop signposting to training options across island and sectors

Many of the businesses and sectors that participated in our study highlighted access to training and skills to understand and develop carbon footprints and decarbonisation plans as gaps. Some sectors want to upskill in-house with other preferring external skills being brought in e.g. from advisory services, so signposting to appropriate training and advice to allow them to do this would be beneficial.

Utilise the CDOs for the islands as contacts for training and support.

In addition, or as an alternative to the above, CDOs could provide more direct support to businesses. This could be encouraged either by further training CDOs in carbon footprint and decarbonisation plan development, or by CDOs being supported to direct businesses to relevant information and resources. This could also offer a routeway for the positions of CNI CDO to be sustainable through a chargeable service provided to local businesses. It would also provide stable employment in supporting decarbonisation.

Training for technicians, electricians, mechanics and other trades

Training for technicians, electricians, mechanics and other trades would allow island businesses greater access to green technologies. In order to be certified for installation and maintenance of these technologies, specific accreditation is often required. Responders stated that gaining these certificates and accreditations is complex and time consuming with minimal support. In many cases Tradesmen are small or even sole businesses that do not have the capacity to become accredited.

Currently islands are more likely to be reliant on Scottish mainland-based company support for installation or design of green technologies. This can be more difficult than for mainland counterparts due to more limited options, impose less competitive prices and have longer delivery times. Securing installation and maintenance on green technology is often extremely difficult in an island, with large delays, higher costs and limited options. Mainland contractors can have geographic exclusions that commonly exclude islands from access to standard services and prices. Addressing this constraint would have multiple benefits, not only by increasing access to low carbon technologies, but by increasing the skills on islands, expanding employment opportunities, and supporting apprenticeships to retain island residents.

Development of sector specific roadmaps

Cost and time have been identified as the most significant area where support is needed across the sectors. However, the priority needs across the sectors have some significant differences. Cost and time constraints were especially notable around seasonal businesses such as tourism and leisure whereas tools and training were more important to agriculture. Renewable Energy, Food and Drink, and Logistics sector responders stated they would like to have access to training to up-skill. Aquaculture, Retail, and the Leisure industry sector responders stated a preference for external skills being brought in (Appendix B Table 3). The remaining sector responders stated all the support options would be useful and had no immediate preference or priority. This all means that a sector targeted approach may be useful in supporting island business.

It would therefore be important to develop specific sector roadmaps within an island context. This could include developing tools such as carbon calculators that account for the sector requirements as well as the island location. These tools would support baselining but should be linked to specific actions and support e.g. funding to help implement their plans. This sectoral approach is supported by the different priorities that were found between business such as:

• To achieve a net zero transition, the retail and food & drink sectors have indicated they would benefit from more assistance in decarbonising their supply chain and ability to use local produce and goods.
• The tourism, leisure and transport sectors would like more infrastructure and local trades assistance to allow for green technologies to be used such as EV chargers and microgeneration.
• Agriculture would like more support in developing their decarbonisation strategies and undertaking carbon audits.

Funding support landscape improvements

There are funds and investment opportunities that may be available for businesses to support decarbonisation efforts (BEIS, 2021). These funds can provide significant financial support and cover a variety of decarbonisation strategies. However, we found that businesses lack the knowledge to access these funds, and face time pressures to complete applications. We also found that there are no means of coordinating a funding search or application process.

These funding application processes are also often complicated with limited assistance offered. Many funds are also only accessible for large organisations or for specific sectors which do not reflect the significant number of SME businesses which account for over 35% of carbon emissions (Energy Saving Trust, 2022). The competitive nature of grants and investments also restrict the access to many who may qualify but do not have the expertise needed to successfully apply and secure funds. Interviewees felt that smaller businesses did not qualify for grants and funding due to a wide range of exclusions. This was especially prevalent among the trades, crofting and farming interviewees.

Finally, the overall capacity and scope of the funding is not sufficient to have impact for enough businesses.

There is the opportunity to address this for CNI islands through reviewing funding guidance and the application process to better reflect the challenges faced by island based SMEs which could be linked to the sector roadmap priorities would support a coordinated approach to meeting the 2040 targets.

The Islands (Scotland) Act 2018 and the 2019 National Islands Plan represent positive steps to support islands and may in time present a key route to address island impacts and opportunities. However, these policy provisions are yet to be fully implemented across all programmes to support all island businesses more directly.

Specific agricultural focused actions

Agriculture has a significant part to play in the net zero target across islands with land use being a major carbon contributor. From our policy research it would seem that there are limited policies and strategies that offer practical actionable support for crofters and small-scale farmers. There can be a disconnect between land use and natural resource protection which may cause policy to become a barrier for those looking to reduce carbon emissions and turn to a more sustainable way of farming. This could include actions such as installation of renewable energy technologies (Solar, Wind or Anaerobic Digestor systems). The general strategic changes to agricultural policy/support mechanisms and subsidy for agriculture should have carbon reduction as a key aspect of framing but also account for island-specific challenges.

Upgrading of island energy infrastructure

Delivering upgrades to islands energy infrastructure is essential in the development and use of renewable energy and associated technologies. This will support island businesses to develop more long-term carbon reduction plans for example by allowing businesses greater access to grid to invest in wind, solar or battery technologies.

Islands are an ideal test bed for the use of mixed renewable energy (tidal, solar, storage and wind). However, the lack of grid capacity severely restricts the ability for companies to develop and test these technologies. It is difficult to gain connections even for domestic or commercial small scale renewable energy technologies.

Many islands suffer from energy insecurity due to grid infrastructure not being reliable and power cuts are common. While there is a nationwide push and promotion of increased renewable energy technologies, all consultees spoken to during the project made reference to significant grid restrictions faced. There is a need for grid infrastructure improvements to support decarbonisation via green technologies across the islands. Without upgrading and improving the grid infrastructure to accommodate more green technology connections, island businesses will struggle to benefit from decarbonisation via green technology.

Promotion of circular economy to reduce emissions from supply chains and waste as part of business decarbonisation strategies

The development of an island circular economy with emphasis on recycling, reuse and sharing of resources. Island communities have fewer recycling options meaning more waste going to general landfills. There are some islands where only reduced recycling is offered, and facilities often overfilled, for example on Hoy, a café owner mentioned this is why she tries to reuse rather than recycle. Many residents try to reuse and upcycle where possible while complying with regulations regarding disposal of waste products. Sharing of tools, some small plant and farming equipment is commonplace with island businesses willing to share and lend equipment where possible and if needed.

Next steps

There are several options highlighted throughout this report that will support island businesses to decarbonise. The key steps that would help are:

• Develop a training programme with the CDOs to enable them to enhance island businesses information routes and understanding. This could also ultimately be a resource to produce business actions plans.
• Develop island specific carbon planning tools such as carbon calculators. These should also account for sectorial differences.
• Develop sector specific roadmaps to carbon neutrality with short and long-term targets.
• Develop a coordinated support package for islands businesses with relevant government agencies and training providers.

References

BEIS, 2021. Net Zero Strategy: Build Back Greener. [Online]
Available at: https://www.gov.uk/government/publications/net-zero-strategy

Energy Saving Trust, 2022. How can policy better support SMEs in the pathway to Net Zero?. [Online]
Available at: https://www.theccc.org.uk/publication/how-can-policy-better-support-smes-in-the-pathway-to-net-zero-energy-saving-trust/

Food Standards Scotland, 2024. Approved Establishments Regiser. [Online]
Available at: https://www.foodstandards.gov.scot/publications-and-research/publications/approved-premises-register

Scottish Government, 2023. Carbon Neutral Islands Project Progress Report. [Online]
Available at: https://www.gov.scot/publications/carbon-neutral-islands-project-progress-report/

Appendices

Appendix A Methodology

This project was undertaken using a range of methodologies and resources. The following sections detail the method used to complete each phase and task.

Phase 1

Phase 1 was to investigate and understand the baseline for current business readiness and the support that is available in a general sense. We also wanted to identify the sector landscape across the CNI islands to allow a comparison between the National sectors and island sectors.

To achieve these goals the tasks proposed consisted of:

• Desktop research to identify the businesses and relevant organisations on each Island
• Graphical analysis of island business distribution
• Policy review of support for decarbonisation, islands and small businesses
• Desk based literature review of wider sector readiness

Business Identification and Analysis

We identified businesses using desk-based research, using online local databases such as commercial directories and cross referencing as best as possible using other online sources such as social media and individual businesses websites to verify current operational status. We recorded results in a CNI target businesses database which was issued to the CDOs for a sense check. CDOs were able to provide invaluable guidance to this stage of the process to refine and target business contacts.

Figure 7: Businesses across the islands

Phase 2 – Engagement Methodology

To allow for maximum outreach, an online survey was created using Survey Monkey for wide spread distribution to the island businesses. The survey comprised of 31 questions that addressed a range of topics that related to the research questions. Readiness, Skills and Needs. The survey was compiled and issued following GDPR privacy standards and all information used in the production of the report has been anonymised.

The surveys were hosted on an online platform and participants were emailed the link to access the surveys. The platform allows for some basic analysis of survey results which was then refined and formatted to create the graphics in section Error! Reference source not found..

Where interviews were held, the interviews were summarised and key comments were selected that best represented the research questions posed in the project, summarised and represented in a graphical way to be clear and concise.

Sectoral comparisons were assessed by filtering and carefully selecting the most relevant questions that provide evidence based data for the questions presented by the project. A table presentation was selected as the most visually appealing way to show how ready the businesses are and what support they require to decarbonise.

Phase 3 – Report production

To compile the data obtained from phase 1 and 2 of the project, we used MS Excel to convert narrated data from interviews into data points for statistical analysis and summarisation. The data accessible from the Survey Monkey online platform was also very useful in providing a clear analysis with multiple filters and analytic tools to aid in the production of statistical graphics.

Selection of the key survey questions to be included in the report were based on the relevance to the key research questions. The full survey was important to gain a full understanding of the awareness and skill level of the participants, however not all were critical to include. We reviewed the 31 survey questions and highlighted those that provided the most detailed information around skills, training, challenges and opportunities. The final question selection was reduced to 10 for the general island findings and 15 for the sector comparison section.

The interviews were well organised by the CDOs and provided a deeper understanding on how the businesses owners felt about support for island net zero transition, how big a priority it was for them and what could encourage them to do more. From the interviews, we discovered that a number of common themes around challenges, opportunities and needs linked the islands and businesses. While there were subtle differences in the themes, the core issues were the same which lends credibility to the small sample when seen across the 6 islands and all interviewees.

Reflections

Challenges in Methodology

Undertaking engagement on a wide scale across various islands is difficult and there has been less participation than we expected. It is essential to have strong connections within the community to promote and encourage participation. CDO connections was very helpful within the islands in getting responses but with limited time available wider engagement was a challenge during island visits. The survey completion rate varied between as low as 3 on Hoy to a maximum of 15 for Yell with the others ranging around 8-12. Interviewees numbered around 3-6 people per visit with the exception of Islay where only 1 in person interview was arranged, however there were phone interviews following the visit.

Online surveys while useful and easy to issue to multiple contacts, rely on the willingness of the recipient to complete them. This reliance has meant that only a small section of island businesses were captured in the survey data, with gaps in the sectors and business sizes. It was hoped that a wide range of sectors and businesses sizes would participate to give a clear picture of the challenges, opportunities and needs of island businesses. This was not the case and the result is that we have significant gaps in data and inconclusive evidence on the current net zero transition readiness on islands.

Lessons Learnt

For engagement reliant projects, it is essential to identify strong community leaders and any steering groups and open discussion early with them on how best to engage with and encourage wide participation. Opportunities to communicate directly with a large number of business owners that were in steering groups were missed. Had we more directly engaged with them in person, perhaps we could have gained more cooperation from a valuable resource.

Visits to the islands were useful and critical in conducting the in person interviews, however time was limited and therefore organising interviews difficult. It may be more productive to contract local residents to undertake the engagement tasks following a set methodology provided by the Project Manager.

The online surveys were useful and provided good data and analysis tools. On reflection, the survey was too long and some questions repetitive and unclear to the participant. While all the questions provided key insight into the carbon related operations of the businesses the final number used in the report was 10-15 out of the 30 and questions asked during the interviews would have been useful to have in the survey to allow for statistical analysis.

1. Detailed results

Our analysis is based on responses to questionnaires and in-person interviews.

Overall CNI readiness

As shown in Figure , around half of the participants are aware of their businesses carbon footprint to some degree, less than 20% are actively tracking it. There is a slight increase in those who are developing a decarbonisation strategy with around 25% stating they have or are developing a plan for their business. We have assumed for this analysis that any non-responding participants do not track their carbon footprint or plan to develop a decarbonisation strategy.

Q5 Are you aware of your organisation’s carbon footprint?
Q6 Do you track your organisation’s carbon footprint?
Q10 Do you have a plan to become carbon neutral or are you developing one?
If yes, which option best describes your current stag of planning? – We have a draft plan: 6 – We are considering writing a plan but have not started preparations: 4 – We have a fully developed: 3 – We have a fully developed carbon neutral plan or strategy: 3 – We intend to write a plan and have started preparations: 3 Note: Number of responses

Sector analysis of carbon strategy development

Sector readiness

Sectors are compared although there were no participants for some e.g. waste and mining. Some participants skipped some survey questions. Table 1 shows the percentage of businesses in each sector tracking their carbon footprints.

Sector barriers to developing a decarbonisation strategy

Responses were separated into sectors to identify any differences that were present between the business types. Few responding businesses were actively tracking their carbon footprints, but only renewable energy sector participants indicated this as not a priority. Many businesses identify time and cost as the main barriers with agriculture and logistics strongly indicating that barriers are cost, time and lack of skills equally. Media sector businesses responded that lack of skills is the main barrier, whereas renewable energy states that cost is the main barrier for them. With tourism, time is the main factor given most are small or sole operator business with significant seasonal pressures.

Decarbonisation actions by businesses

The following provides the evidence on current actions being taken by the participating CNI businesses in general from the 6 islands.

The majority of participating businesses are actively taking steps to reduce their carbon footprint, however, as shown in Figure , these actions are largely recycling.

Sector actions to decarbonise

The following table shows the differences across the sectors from the participating CNI businesses in terms of the level of activity presently underway.

Skills training to help decarbonisation

Table 9: Existing carbon reduction skills within sectors

© Published by Aquatera, 2024 on behalf of ClimateXChange. All rights reserved.

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

The higher upfront cost compared to gas boilers is a challenge for increasing rollout of heat pumps and effective financing options are required to enable this.

This report identifies how innovative business models, such as subscriptions including payment plans, financing and ‘heat as a service’ models, could support the rollout of heat pumps by helping with the upfront investment, which is often a challenge for consumers.

Through a literature review and analysis, and in-depth discussion with stakeholder groups, it explores how three business models could be implemented in Scotland via pilot schemes.

Summary of findings

• A limited number of heat pump finance offerings are currently available to customers in Scotland. Other than an upfront purchase, most of these are finance only payment plans for the purchase of the heat pump only. Uptake for these plans is very low. Funding from the Scottish Government currently includes an up to £7,500 interest-free loan and a grant to the equivalent value. There are heat pump on subscription offerings across Europe, but these are also fairly limited, reflecting an immature market.
• The following range of business models could be applied to heat pumps in Scotland: a) finance only, b) financing lease, c) subscription, d) heat as a service.
• Adding the installation of energy efficiency measures, an energy tariff suitable for heat pumps and energy advice to these propositions could increase their appeal.
• There are non-financial barriers such as complexity of installation, consumer difficulties in understanding fuel bill savings and a current lack of consumer demand.
• Specific barriers to heat pump subscription models include lack of understanding and reassurance around consumer protection and contractual issues – for example, when moving properties.
• Stakeholders have a mixed appetite for piloting new approaches, with the main challenge being provision of finance. Other challenges and risks include ensuring heat pump performance and supply chain capacity.

For further details, please download the report.

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

Green hydrogen, produced by electrolysis using renewable or low-carbon electricity, is expected to play a key role in reaching the Scottish Government’s net zero emission targets.

The purpose of this study was to determine if Scotland can produce green hydrogen at scale and export it at a competitive cost to the EU market.

It explored the costs of producing hydrogen in Scotland, Chile, Norway, Morocco and France and the northeast region of the USA and exporting to northwest Europe, through a levelised cost model and literature review.

The study focused on:

• Production of hydrogen at scale
• Transport via pipeline, entering the EU via Rotterdam
• Transport via shipping ammonia: The hydrogen produced is converted to ammonia, shipped to Rotterdam and converted back into hydrogen in the Netherlands.
• Transport via shipping compressed hydrogen

Summary of findings

• From the countries analysed, hydrogen production is cheapest in France given its access to low-cost nuclear electricity. The most expensive is Scotland due to the higher cost of power from offshore wind compared with the other low-carbon power technologies used. Other countries are expected to become more competitive as low-carbon electricity costs reduce and technology improves.
• The most cost-effective transport option varies depending on distance, volume and technology. For longer distances, such as from the USA and Chile, converting hydrogen to ammonia and shipping via ammonia vessels is most effective. For shorter distances, pipeline or compressed hydrogen transport options are more cost-efficient. Pipelines are most cost-efficient when repurposed and the capacity is fully utilised. Where existing infrastructure is not available and the pipeline is not fully utilised, shipping compressed hydrogen offers a cost-saving alternative for shorter distances.
• Scotland’s proximity to Rotterdam gives it a competitive advantage. To outcompete countries that are closer to Rotterdam, production costs in Scotland must decrease.
• Considering the evolving state of the hydrogen industry, cost estimates for production and transportation carry uncertainty.

For further details, please download the report.

Scotland’s electricity system is undergoing a transformation with rapid increases in installed wind and solar electricity generating capacity. This is coupled with the phase out of nuclear and unabated gas power stations.

This will impact on Scotland’s electricity system security of supply, which has historically relied on large, centralised fossil fuel power plants. These can ramp power production to meet demand, in addition to grid network connection to the rest of Great Britain. Here ‘security of supply’ refers to the ability of the system to reliably and continuously provide a sufficient amount of electricity to meet the demands of consumers.

In this report, we explore issues around security of supply in Scotland’s electricity system in the transition to net zero greenhouse gas emissions by 2045.

We examine international examples of national and regional electricity systems transitioning to net zero and review the potential impact of electricity market reform. We use scenario modelling to quantify security of supply and import/export metrics for the expected technology pathway in Scotland.

The report also looks at the security of supply of a self-sufficient Scotland, with no interconnection to Europe or the rest of Great Britain, in addition to a low capacity and high demand scenario to further test Scotland’s future electricity system.

For a full list of findings and further details please read the report.

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

DOI: http://dx.doi.org/10.7488/era/3737

Executive Summary

Overview

Scotland’s electricity system is undergoing a transformation with rapid increases in installed wind and solar electricity generating capacity. This is coupled with the phase out of nuclear and unabated gas power stations.

This will impact on Scotland’s electricity system security of supply, which has historically relied on large, centralised fossil fuel power plants. These can ramp power production to meet demand, in addition to grid network connection to the rest of Great Britain. Here ‘security of supply’ refers to the ability of the system to reliably and continuously provide a sufficient amount of electricity to meet the demands of consumers.

In this report, we explore issues around security of supply in Scotland’s electricity system in the transition to net zero by 2045. We examine international examples of national and regional electricity systems transitioning to net zero and review the potential impact of electricity market reform. We use scenario modelling to quantify security of supply and import/export metrics for the expected technology pathway in Scotland.

The future security of supply of Scotland is subjected to stress tests, including disconnection of offshore wind farms; low variable renewable power output; unavailable gas power generation in Scotland; unavailable interconnectors; battery storage failures; and an unavailable connection to the rest of GB. The report also looks at the security of supply of a self-sufficient Scotland, with no interconnection to Europe or the rest of Great Britain, in addition to a low capacity and high demand scenario to further test Scotland’s future electricity system.

Key findings

• Examples of national and regional electricity systems operating with high proportions, in excess of 100%, of renewable electricity are typically dominated by hydropower and pumped hydro storage reservoirs. These are dispatchable and offer high levels of security of supply.
• Scotland and Denmark are leading examples of national electricity systems integrating large shares of variable renewable energy sources, but rely on imports with neighbouring countries.
• Potential changes to electricity market arrangements such as splitting the wholesale market, locational pricing and an enhanced capacity market could have impacts on future investment in renewables and flexibility technologies in Scotland.
• Under the System Transformation scenario there will be a reduction in traditional firm generation capacities in Scotland. This includes no nuclear and reduced gas power plant generation when changing to carbon capture and storage technology. However, these losses will be offset by vast increases in wind and solar installed capacity, as well as increasing low-carbon firm generation capacity in the form of biomass, hydrogen and abated gas power plants.
• Security of supply metrics for Scotland in the System Transformation scenario for the years up to 2045 were found to be within the current GB reliability standards and comparable to current levels. Security of supply in Scotland improves in the transition towards net zero by 2045 due to large increases in generation capacity and storage.
• Peak demand in Scotland is expected to rise from around 5000 MW in 2021 to around 9000 MW by 2045 but is exceeded by generation, even when considering expected availability in real time. While the generation capacity in Scotland may seem excessive in the context of security of supply in this scenario, it is utilised to decarbonise and provide security of supply to GB as a whole.
• Scotland will continue to be a net electricity exporter to the rest of GB and net exports will increase from current levels. There will be an increase in the level of import from the rest of GB due to increased demand, coupled with increased reliance on variable wind power generation, which leads to more imports during low wind periods.
• Testing of the future Scottish electricity system, assuming low installed capacity for thermal power plants, low B6 boundary expansion and high future peak demand, shows lower security of supply in 2030 than the GB reliability standard.
• In 2025 and 2030 disconnection with the rest of GB has the highest impact of all of the stress tests conducted, followed by unavailable interconnectors and gas supply issues. This implies that there is a high reliance on imports from and exports to the rest of GB in maintaining the capacity adequacy in Scotland. However, its significance is negligible from 2035, when there is a large increase in offshore wind capacity and additional capacity of battery storage, pumped hydro, hydrogen power plant and biomass.
• A self-sufficient Scotland with no connection to the rest of GB and no interconnector capacity would violate the GB reliability standard in the years 2025 and 2030, mainly due to periods of low wind and renewables output without sufficient dispatchable supply capacity. However, by 2035 the security of supply metrics are within historical values and improve further in the following years. We find 250 MW and 1000 MW of additional equivalent firm capacity would be needed in 2025 and 2030 to meet minimum reliability standards and historically typical standards respectively. This would be the equivalent of an additional 1,553 MW to 6,211 MW installed capacity of offshore wind.

Glossary

Introduction

Background and aims

Scotland is committed to net zero greenhouse gas emissions by 2045 through the Climate Change (Emissions Reduction Targets) (Scotland) Act 2019 [1]. This means net zero emissions across all sectors of the economy, including from the energy system. In the power sector, traditional thermal generation, such as nuclear power and gas power plants are being retired and there are ambitions for realising 8-11 GW offshore wind capacity by 2030 [2]. Under some net zero scenarios this could increase to more than 35 GW by 2045 in Scotland [3]. Additionally, under National Grid’s ‘Leading the Way’ scenario in Scotland solar PV rises from 0.5 GW in 2021 to 6 GW in 2045, and onshore wind rises from 9 GW in 2021 to 27 GW in 2045.

This raises the importance of security of supply in Scotland with an electrical system that has high levels of weather-dependent wind and solar energy. The transition to net zero brings new challenges to Scotland’s electricity system security of supply:

• Torness nuclear power plant is due to close before the end of this decade resulting in the loss of the baseload output from this electricity generator.
• Peterhead gas power station may close as an unabated gas power plant and be replaced by a gas power plant fitted with carbon capture and storage technology. It is uncertain whether new carbon capture power plants can be operated flexibly or will be required to produce electricity round-the-clock.
• Increased reliance on intermittent renewable energy sources causing greater disparity between generation and demand on hourly, daily, monthly, and seasonal timescales.
• Increased need for electrical network expansion and reinforcement to transport renewable electricity to high demand areas.

The emissions reduction pathway shown in the 2020 climate change plan update [4] accordingly sets out a vision for net zero emissions from the electricity sector by 2029.

In this report, we:

• Investigate international examples of national electricity systems operating/moving towards reliance on renewables.
• Review expected/planned policy or regulatory developments, such as locational pricing, which could impact the future system.
• Assess technology developments needed in Scotland to ensure a secure and reliable supply of low and zero carbon electricity to 2045.
• Assess the likely impacts on transfers of electricity from/to Scotland and the rest of GB, in a Scottish electricity system powered almost entirely by intermittent renewables.
• Calculate additional volume and type of generation that would be required for Scotland to have an entirely self-sufficient system (also including black start capability).

Security of supply

Security of supply in electrical power systems is the ability to match supply and demand with high probability, both under normal and unexpected conditions. This includes the coldest periods when peak demand often occurs; during outages of large power plants or interconnectors; and dark, windless periods when there is low renewable generation.

Challenges for future security of supply

Meeting the peaks in electrical demand is key in determining security of supply. If this demand can be met with high probability, then it is likely that all other periods with lower demand can also met. However, in systems where a high proportion of generation is from variable renewable sources then there will also be periods when high generation coincides with lower demand, which can lead to excess generation. Periods of excess generation is not the focus of this report but it is recognised that this can also provide challenges in an electrical system, such as costs of constraints, and that these periods require reliance on flexibility technologies such as storage and interconnection.

Peak electrical demand is expected to grow in the UK^[1] from around 60 GW seen for the past decade to 100 – 115 GW in 2050 [Figure 1]. These rises are strongly driven by electrification of heat and transport.

Figure 1 Peak demand during average cold spell increasing according to Future Energy Scenarios

In the future, it is expected that there will be increasing flows of power between Scotland and the rest of GB. The extensive wind resources, both onshore and offshore in Scotland, offer high and consistent wind speeds which makes Scotland an attractive place to build wind farms. However, electricity demand is far greater in England than in Scotland. In 2021 peak electricity demand was around 11 times higher across the rest of GB (55 GW) compared with Scotland (5 GW). National Grid’s ‘System Transformation’ scenario from the Future Energy Scenarios (FES) predicts broadly similar levels of installed wind capacity by 2050 (onshore and offshore) in the rest of GB (around 71 GW) and in Scotland (around 59 GW) [3]. This will lead to more reliance on the electrical network for transmitting the necessary electricity to ensure security of supply on both sides of the Scotland/England power system boundary.

Security of supply in the UK in National Grid’s Winter Outlook

Peak electricity demand often occurs during cold weather, and National Grid publish a winter outlook on security of supply every year. The report provides analyses of forecasted weather, expected power plant issues, and estimated import and export capabilities of interconnectors to Europe. The impacts on probability of the UK electricity system to be able to reliably meet electricity demand are also assessed. For more information on the 2022/23 winter outlook see Appendix 12.1.

Under normal conditions the electrical power system at present meets security of supply thresholds, but wider geopolitical issues have shown that it is vital to consider ‘unlikely’ stress events to the system. The winter outlook gives the current view on security of supply in the short-term but given that it takes years to build electrical power infrastructure it is important to consider how security of supply will evolve in the future.

The transition to net zero is informed by creating scenarios for the expansion of capacities of generation, demand, flexible technologies such as batteries and pumped hydro, and electrical networks.

Issues around operability

Black starts are the process for recovering the entire power grid following a highly unlikely^[2] complete shutdown. However, not all generators have black-start capability. Conventionally, it is provided by a limited number of large coal, gas, and diesel generators. Following a highly unlikely event of a total or partial shutdown of the national electricity transmission network, black start plants can start independently, by using on-site equipment and fuel. They are independent of wider system input or specific weather conditions and can set up a skeleton network. Gradually different components can be reconnected to re-establish normal operation.

Wind turbines were previously viewed as unsuitable for black start due to dependence on external electricity before they can begin generating power. However, some of the latest designs are capable of self-starting. For example, in 2020, the 69 MW Dersalloch wind farm provided a black-start function through alternative control of power electronics using a virtual synchronous machine approach to restart part of the Scotland grid [5]. Battery storage, which has seen fast growth in UK, can also contribute to a black start. National Grid has committed to consider the provision of black start from non‑traditional generation technologies to facilitate the restoration of the future GB power system [6].

Aspects of security of supply also include the sufficient provision of ancillary services to stabilise power system operation. Ancillary services are not within the scope of our work, but a short commentary can be found in Appendix 12.2.

Scotland’s electricity system

Scotland’s electricity system operates as a part of the wider GB power system meaning electricity supply and demand must be always equal across the whole of GB. Generators anywhere in the GB power system can sell electricity to any demand, regardless of distances, through bilateral agreements and power exchange markets. It is then the responsibility of the energy system operator, National Grid ESO, to redispatch generation and demand to ensure that the physical electrical network can cope with the trades.

In the north of Scotland, the transmission and distribution network are operated and owned by Scottish & Southern Electricity Networks (SSEN). In the south of Scotland the transmission and distribution network are operated and owned by Scottish Power Transmission (SPT) and Scottish Power Energy Networks (SPEN) respectively. These transmission networks interface with the transmission network operated by National Grid Electricity Transmission which covers England and Wales, see Figure 2.

The boundary between Scotland and the rest of GB will be subject to future increased power transfer requirements due to additional onshore and offshore wind generation locating in Scotland. When there is low generation output in Scotland there may be power flowing from the rest of GB to Scotland to meet demand. However, these flows will be low compared to the flow from Scotland to the south so there is unlikely to be further requirements for network extension to support this on top of those for flows from Scotland.​ According to National Grids ETYS21 [7] there is currently a total of 6,100 MW transfer capability between Scotland and the rest of GB^[3].

Figure 2 Network infrastructure in 2022 across the B6 boundary [7]

Table 1 outlines the installed firm generation and the corresponding de-rated capacity in Scotland for the year 2021. Firm generation is defined here as generation types which can generate when required, and independently of external factors such as weather conditions. We also account for “de-rated” capacities where aspects such as outage rates are incorporated. Table 1 shows the de-rated firm generation and interconnector capacity in Scotland in 2021 was 8,489 MW while peak demand was 4,890 MW. Peak demand as a percentage of total firm de-rated capacity in Scotland was therefore 58%, meaning that there was secure installed firm capacity which is likely to meet demand in 2021. Therefore, the current generation mix in Scotland’s electricity system provides sufficient security of supply.

In the next sections, we will investigate scenarios for what the future electricity system in Scotland will look like and undertake more detailed analysis into how security of supply may evolve.

Table 1 Total and de-rated firm generation and interconnector capacity (MW) in Scotland in 2021 (see Appendix 12.13 for de-rating factors)

100% renewable electricity systems

Renewable electricity generation technologies can be split into two categories related to the challenges of accommodating them into power grid [8] [9]:

• Variable Renewable Energy (VRE): dependent on short-term weather conditions, and typically use invertors to interface to the grid, for example, wind and solar; and
• Non-VRE technologies: dispatchable generation using synchronous generators including hydro with reservoir, biomass, geothermal, and concentrating solar power with thermal storage.

For VRE, additional flexible technologies such as dispatchable generation and energy storage are required to compensate intermittency. For non-VRE generation, the timing and volume of production can be adjusted to follow demands and market developments.

In this work, a 100% renewable electricity system is defined as: a system that operates exclusively on renewable energy sources, such as wind, solar, hydro, geothermal, and bioenergy. It does not rely on non-renewable sources such as fossil fuels, nuclear energy, or other non-sustainable sources of energy. The renewable sources can be instantaneous outputs from renewable generation, discharged energy stored previously from renewable electricity, or even imported renewable electricity from connections with neighbouring systems. 100% renewable electricity system is technically achievable, and this section explores countries and regions where they exist. However, there are exponentially increasing costs to reach 100% [10] [11] [12].

Several national electricity systems in the world already operate with, or close to, 100% renewable electricity. Details can be found in Appendix 12.3. Further detail on national electricity systems with high shares of VRE generation (operating with less than 100% renewable energy) can be found in Appendix 12.4. Details of regional electricity systems operating with near to 100% renewable electricity can be found in Appendix 12.5.

Table 2 summarises key features in countries and regions with high share of renewables in power production. For countries already operating with (or very close to) 100% renewable electricity supply, the share of VRE is actually very low. For countries and regions with a high share of VRE generation, despite future 100% renewable electricity targets, fossil fuel dispatchable generation is still playing a major role to provide flexibility – either from gas and coal plants within its system or imported through connections.

Table 2 Comparison between counties and regions with high share of renewable power production (2020 data, see Appendices 12.3 – 12.5)

Renewable electricity in Scotland

In 2020, the generation of renewable electricity in Scotland was equivalent to 97.4% of its gross electricity consumption. However, as shown in Figure 3, fossil fuel generation accounted for 15.6% and nuclear for 16.9% of the total electricity consumption in Scotland.

Figure 3 Proportion of electricity consumption by fuel in Scotland 2022 [13]

Scotland also exchanges large quantities of electricity with England, Wales, and Northern Ireland, mainly exporting rather than importing. To achieve a reliable and resilient 100% renewable electricity system in Scotland will require a set of low-carbon solutions to fill the increasing gap of flexibility requirement when more renewables are set to connect but fossil fuel and nuclear generation are phased out.

Changes to electricity markets

The transition to a net zero energy system requires large-scale building of new power infrastructure. For example, upgraded and new transmission lines to meet increasing power demands; large onshore and offshore wind farms in remote areas; dispatchable power plants running on Hydrogen or fitted with carbon capture and storage (CCS) technology; and flexible technologies which can respond at different timescales to increasingly variability such as pumped hydro storage.

The need for reform is exemplified by curtailment costs in the UK doubling in just one year, from £145 million in 2019 to £282 million 2020 [14]. Well-designed electricity markets should efficiently incentivise capacity investment as well as dispatch of generation and network assets to facilitate the net zero transition.

Significant reforms of electricity markets in the UK are required to enable the transition to a net zero energy system at low cost while ensuring security of supply. Potential changes to electricity market arrangements were outlined in a consultation document on potential reforms published by BEIS in July 2022, ‘Review of electricity market arrangements’, referred to as REMA [15]. The aim of REMA is to establish the electricity market reform necessary for a fully decarbonised electricity system by 2035, which supports the transition to an economy-wide net zero energy system by 2050. The reforms are intended to form the final critical step towards supporting the net zero transition.

The main approaches outlined in REMA are reforming to a net zero wholesale market; markets suited to the roll out of mass low-carbon power; incentivising investment in flexibility technologies such as by introducing locational pricing; ensuring capacity adequacy; and reforming ancillary services which enable operability. There is significant debate around the advantages and disadvantages of these potential reform measures. These approaches and potential impacts on the Scottish electricity system are outlined below. More background information on these reforms can be found in Appendix 12.6.

Technology development in Scotland to 2045

Scotland pathway using FES22

We use National Grid’s FES [3] as the baseline for technology development in Scotland to 2045. Based on FES pathways, we extracted and scrutinised data specifically for Scotland. FES is external to the Scottish Government and takes a UK-wide approach and may not necessarily be consistent with Scotland’s annual emission targets. However, it has a high level of detail including a regional breakdown which means that Scotland specific data can be extracted. We modelled metrics that provide a measure of security of supply and investigate this with an extended set of stress tests applied.

Four scenarios are presented in FES with three pathways meeting net zero targets and one pathway that falls short (see Appendix 12.7). This report uses the System Transformation scenario as the baseline for installed firm generation capacity, installed VRE generation capacity, peak demand, installed storage capacity, network connection to England and Wales and interconnectors to Northern Ireland and Norway. The System Transmission scenario was chosen because it represents a middle-ground in terms of the expansion of technologies compared to the Leading the Way and Falling Short scenarios. It is recognised that the System Transformation scenario is not aligned with Scottish Government policy with a high usage of hydrogen for heating. The following modifications were made to the System Transformation scenario:

1. Offshore wind installed capacity by 2030 was changed from 7,000MW to 9,500 MW in line with Scottish Government targets.
2. Interconnector capacity was extended from solely the 500 MW Moyle interconnector to this plus 700 MW interconnection to Norway (1200 MW overall) from 2035 which is in line with the Consumer Transformation scenario.

We used the PyPSA-GB model of the electrical power system for modelling FES data and for calculating power flow, see [16] and Appendix 12.9 for more details. Data is included for the years 2021, 2030, 2035, 2040, and 2045.

Installed firm generation

Figure 4 shows the installed firm generation capacity in Scotland for the System Transformation scenario.

• The last remaining nuclear power station in Scotland, Torness, closes in 2028.
• The existing Peterhead Combined Cycle Gas Turbine (CCGT) power plant is assumed to close in 2026 and open as Peterhead 2 with reduced capacity (1,200 MW CCGT to 910 MW CCGT + CCS) in 2027. The CCS Gas generation capacity is then doubled between 2040 and 2045 to 1,800 MW.
• Hydrogen powered generation capacity is also added with 690 MW by 2040 and 1,924 MW by 2045.
• Hydro power plants see moderate increases out to 2045.
• Significant increases in biomass generation capacity to around 1,900 MW in 2045.
• 

Figure 4 Installed firm generation capacity (GW) in Scotland under the System Transformation scenario

Installed variable renewable generation

Figure 5 shows the installed VRE generation capacity in Scotland for the System Transformation scenario.

Figure 5 Installed VRE generation capacity (GW) in Scotland under the System Transformation scenario. Offshore wind in 2030 has been changed to 9.5 GW to reflect Scottish Government ambitions of 8-11 GW

• Solar Photovoltaics capacity consistently grows from 462 MW in 2021 to almost 4,000 MW in 2045.
• Wind offshore is projected to grow from 1,700 MW in 2021 to 33,900 MW in 2045. The Scottish Government ambitions for 8,000-11,000 MW of offshore wind capacity by 2030 is not met in the System Transformation scenario. We modified the scenario to meet this target by inserting an installed capacity of 9,500 MW for offshore wind by 2030, in order to test the system under the conditions that this target is achieved.
• Wind onshore is projected to grow from 8,900 MW in 2021 to 23,900 MW in 2045.

Installed storage capacity

Figure 6 Installed storage capacity in Scotland under the System Transformation scenario.

• Pumped storage hydroelectric installed capacity forms the majority of installed storage capacity in Scotland in 2021. It is projected to rise to above 2,000 MW by 2040. There are several potential pumped storage projects in the pipeline: Coire Glas 1,500 MW [17], Red John 450 MW [18], and Corrievarkie 600 MW [19].
• Battery storage is projected to increase substantially from 124 MW in 2021 to 1,800 MW in 2030, followed by more modest growth to 2,100 MW by 2045.
• Compressed air energy storage (CAES) and liquid air energy storage (LAES) are also projected to have increasing capacity from 0.9 MW of CAES and 1.4 MW of LAES in 2021 to 1,100 MW of CAES and 553 MW of LAES in 2045.

The timescale of usage of these electrical storage types is constrained by the time it takes for each technology to fully discharge at full power. Batteries in FES are assumed to be suited to intra-day charging/discharging cycles. Pumped storage, CAES, and LAES are assumed to be capable of charging or discharging at maximum output for a longer period of time. These storage types are suited to system balancing on seconds, hours, and days timescales but these, bar pumped storage, are unlikely to be used for long-duration storage where balancing is required on weeks and months timescales due to a prolonged period of low VRE output. The FES scenarios mainly rely on hydrogen as a storage medium for these longer timescales.

Peak demand

Figure 7 shows the projected peak electricity demand in Scotland under the System Transformation scenario. There is a steady increase in peak demand from 4,600 MW^[7] in 2021 to 8,700 MW in 2045.

Figure 7 Peak electrical demand during GB-wide average cold spell in Scotland under the System Transformation scenario.

The System Transformation scenario assumes that most heating is met by Hydrogen^[8] (see Appendix 12.8), which results in a lower peak demand than in Consumer Transformation (heating is primarily electrified). The Consumer Transformation peak electricity demand for Scotland in 2045 is 11,300 MW due to most heating being met by electrification through heat pumps. This peak is 2,600 MW higher than the System Transformation assumption.

The peak demand shown here does not include electrical demand from electrolysers producing hydrogen. FES analysis assumes that electrolysers can be turned off during peak demand, and therefore, do not need to be included in calculations for security of supply metrics. However, our analysis does include this demand for power flow analysis and import and export calculations.

Transfer capability and interconnectors

The only interconnector from Scotland to outside GB is currently the Moyle interconnector to Northern Ireland. The Moyle interconnector was limited in transfer capability to 160 MW in 2021, but from 2022 has increased to its full capacity of 500 MW. We used the Consumer Transformation projections for interconnection expansion which includes a 700 MW connection to Norway by 2035 in addition to the 500 MW Moyle interconnector. This modification was made to ensure the baseline includes a higher interconnection for Scotland, and then a stress test on the unavailability of interconnectors could explore the impact on security of supply of no connection with Northern Ireland and Norway.

Transfer capability across the B6 boundary is projected to increase about four-fold from 6,100 MW in 2021 to 24,700 MW in 2040 for the System Transformation scenario. This increase is to enable power flow from the increased wind generation in Scotland to the rest of GB. Power flow to Scotland will be lower than from Scotland, so does not affect the transfer capability requirements. This scenario projection is substantially higher than increases in the Network Options Assessment (NOA) due to higher projections for installed capacity of renewable generation in Scotland. National Grid’s Electricity Ten Year Statement [7] includes more details on the future boundary transfer capability requirements for the B6 boundary which connects Scotland’s transmission network to the rest of GB.

Measuring security of supply

This report focuses on capacity adequacy as a measure of security of supply, which ensures that we always have enough energy to meet our needs. National Grid ESO publish capacity adequacy analysis for the GB system, often in its winter outlooks and FES reports. Given the scope of this work, a similar standard approach is used, with a focus on the Scotland system. The interaction with the rest of the GB system is modelled as flow across the boundaries.

The GB standard for generation adequacy uses the Loss of Load Expectation (LOLE) as the indicator of supply reliability, complemented by other relevant risk metrics which are detailed in Appendix 12.10. LOLE is defined as the expected number of hours over a period in which supply resources are insufficient to meet demand. It provides a measure of security of supply over a statistically long-term period, such as a year. The current reliability standard for LOLE in GB is set to no more than three hours in a year.

De-rated system margin is used as a proxy for risk of loss of supply. It is more useful as a measure of security of supply than installed capacity, as it accounts for the probability of a forced outage.

Security of supply metrics for System Transformation

De-rated system margin

An overview of the forecasted de-rated margin for Scottish system in the System Transformation scenario is shown in Figure 8. While peak demand sees steady growth, it is exceeded by the increase in available firm capacity (including the equivalent firm capacity of VRE) that can serve peak demand with high probability.

Figure 8 of de-rated supply capacity, peak demand and supply margin of Scotland for System Transformation from 2025 – 2045

The de-rated system margin increases from 2,200 MW in 2025 up to 12,200 MW in 2045. The capacity of wind shown in Figure 8 are de-rated using equivalent firm capacity factors (ranging between 13-17% in recent NG reports [20] [21] [22]). This represents the wind generators contribution to security of supply at stress events. Due to the significant amount of onshore and offshore wind added into the system, from 2035 onwards the de-rated wind capacity alone is higher than the peak demand. This ensures a very high level of de-rated system margin.

The GB supply margin under System Transformation can be found in Appendix 12.11.

Loss of load expectation

Figure 9 LOLE results for System Transformation in Scotland from 2021 – 2045

In line with the high de-rated system margin the calculated LOLE of Scotland’s electrical system stays at a very low level for the System Transformation scenario in all modelled years. The lower the LOLE number, the lower the risk of insufficient generation to meet demand. From our results, the LOLE increases marginally from 0.020 hours per year in 2025 to 0.023 in 2030. The increase is due to the anticipated closure of nuclear power stations over the 5-year period. This is still significantly below the 3 hours currently allowed in the GB reliability standard. The rise in LOLE between 2025 and 2030 could be higher but the addition of 7,870 MW wind capacity during this period helps to mitigate the effects of phasing out nuclear generation.

LOLE values from 2035 onwards are less than 0.0001, and so low that statistically the loss of load can be considered highly unlikely. This very low LOLE from 2035 is attributed to the significant influx of new electricity generation of various types in the Scottish system in the System Transformation scenario, e.g., Scotland’s wind capacity is projected to increase by over 25,000 MW, reaching 49,400 MW in 2035^[9], the largest increase over a 5-year period in the scenario. Even with an Equivalent Firm Capacity (EPC) factor of 16.1%, wind energy alone is enough to provide reliable generation equivalent to 8,400 MW, enough to meet Scotland’s peak demand of 6,000 MW in 2035. The addition of biomass, Hydrogen, and pumped storage capacity from 1,223 MW in 2035 to 4,648 MW in 2040 significantly increases the dispatchable electricity sources in Scotland. This also exceeds the Scottish demand growth (1,500 MW) during that period, further enhancing supply security.

In practice, the actual target LOLE for the GB system operator has been less than 3 hours. The LOLE reported in National Grid’s Winter Outlook in 2021 and 2022 was 0.3 and 0.2 hrs/year for the GB system. The Scottish electrical system is modelled to have a lower LOLE than the GB system. In 2021 the Scottish LOLE was modelled as 0.108 hrs/year and this is expected to further decrease in the future.

Power dispatch

Power dispatch is the cost-optimised mechanism by which power needs and demands are balanced. Power dispatch modelling can be used to illustrate security of supply by demonstrating how generation and storage are being used to meet demand. Power dispatch modelling outputs are for the same 2-day peak period in 2045^[10]. Interconnectors are included in the power flow calculation but excluded from modelled output figures to provide focus on the role of generators and storage.

Figure 10 shows the power dispatch of the Scottish electricity system for generation, storage, and export at the B6 boundary (where Scotland connects with the rest of GB) for the System Transformation scenario. Offshore and onshore wind power dominate generation, and there are large power export flows across the B6 boundary to the rest of GB. Storage technologies and biomass are dispatched, while exports continue to the rest of GB, during this high demand period. The equivalent power dispatch at the same peak period for GB^[11] can be found in Appendix 12.11.

Figure 10 Power dispatch of Scotland for System Transformation in 2045 over 2-day peak period.

Imports and exports

Scotland supports the overall GB system with net exports of power across the B6 boundary. Figure 11 and Figure 12 show the monthly import (from rest of GB to Scotland) and exports (from Scotland to rest of GB) across the B6 boundary. Outputs were obtained by running the model with historical data for 2021 and the System Transformation scenario for 2045. Scotland is a net exporter to the rest of GB and exports will increase in future^[12]. There will also be an increase in the level of import from the rest of GB to Scotland which could be due to increased demand coupled with increased reliance on intermittent power generation. The level of import and export have a seasonal pattern, with higher imports in the summer and higher exports in the winter. This is due to higher wind generation and demand in winter than in summer which results in more opportunities to export to the rest of GB.

Figure 11 B6 monthly import in 2021 and 2045 under the System Transformation scenario

Figure 12 B6 monthly export in 2021 and 2045 under the System Transformation scenario

Stress testing Scotland’s security of supply

Our modelling has shown that Scotland’s electricity system has a low probability of being unable to meet demand in the modelled years. However, the assumptions are based on a particular set of conditions and do not account for the full range of possible situations. Stress tests were used to test the security of supply of the Scottish electricity system beyond the original scenario conditions (Figure 13).

Figure 13 Network map of Scotland and stress tests scenarios

These are summarised relative to the System Transformation scenario base case in Table 3.

Table 3 Summary of assumptions used in stress testing scenarios

We investigate the power flow for each of the stress tests and the security of supply metrics up to 2045. We also analyse the impact on imports and exports from/to Scotland. All stress tests are applied for 3 days either side of peak demand. All the stress events are applied to the base case independently, and are assumed to last the whole week in which the peak demand occurs.

Security of supply for the stress tests

Full outputs from stress tests can be found in Appendix 12.12. Figure 14 summarises the LOLE for all the stress test cases. During peak demand periods, the impact of unavailability of supply are higher than other times of the year. The LOLE for all stress tests is within the three hours/year reliability standard, and are below the modelled 2021 Scottish LOLE of 0.108 hrs/year, except for B6 failure in 2025 and 2030 and interconnector failure in 2030. The system from 2035 onwards is very secure with a low LOLE.

In 2025 and 2030 the stress test of disconnection with the rest of GB has the highest impact on the security of supply as measured by LOLE, followed by unavailable interconnectors and gas supply issues. This implies that the reliance of import from the rest of GB in maintaining the capacity adequacy in Scotland is more than the other supply types. However, its significance becomes negligible from 2035 due to a large increase in offshore wind capacity in the Scottish system and additional capacity from battery storage, pumped hydro, Hydrogen power plant, and biomass in subsequent years.

(a)

(b)

Figure 14 (a) LOLE for Scotland in the stress test cases (2025–2045); (b) GB 3h/yr limit added for comparison

Import and export for the stress tests

The stress tests have impacts on the imports and exports across the B6 boundary between Scotland and the rest of GB. Countries in Europe increasingly exchange power with each other, particularly to share cheap abundant electricity, as has been the case historically with France exporting nuclear power to central Europe and Denmark exporting wind power to Norway who can store this in their large pumped hydro schemes. Scotland shares an electricity market with the rest of GB but imports and exports are a useful measure of the dependence on the power exchange across the B6 boundary.

Figure 15 shows for each stress test the total import and export across the B6 boundary over the 6-day period the stress tests are applied, including the peak GB demand period in the middle of the 6 days. The base case in 2045 sees increases in imports due to closure of Torness nuclear power plant and reduced capacity of Peterhead.

Figure 15 Import and export for the stress tests across the B6 boundary

The stress tests for offshore wind farm failures, gas power generation in Scotland unavailability, battery failures, and interconnector issues result in increased imports into Scotland. The low VRES output stress test sees Scotland become a net importer over the 6-day period modelled. The following findings are identified:

• Offshore wind farm failures reduce total wind generation over the period resulting in higher imports and lower exports.
• The low VRES period reduces total wind generation by a greater degree than the offshore wind farm failure meaning that there are more imports than exports.
• Gas supply issues reduce the capability of Scotland to provide firm generation over the 6-day period, resulting in more periods where imports from the rest of GB are required, typically when there is low wind generation. This has minimal impact on imports and exports during the modelled period.
• Battery failure decreases the ability of the system to store excess renewable power generation to be utilised later during low VRES periods. This has minimal impact on imports and exports during the modelled period.
• Interconnector issues reduces exports of excess wind generation to Norway or Northern Ireland, at the same time as reducing imports from these countries to meet demand when there are higher electricity prices in Scotland. The result is slightly increased imports, and increased exports which are exported to the rest of GB rather than to Norway or NI.

Overall, the low VRES output period has the largest impact on imports and exports from/to Scotland, followed by the offshore wind farm failures. This highlights the importance of wind power generation in the future Scotland electricity system. Interconnectors to NI and Norway have the next biggest impact, but this will likely be more impactful under other FES scenarios which see larger increases in interconnector capacity. The battery failure and gas supply issues have minimal impact on the imports and exports in the modelled period.

Self-sufficient Scotland

In this section we assess the impacts of Scotland having an entirely self-sufficient future electrical system. We modified our original model (Table 3) to consider Scotland as an isolated electrical network in the self-sufficient base case. All interconnections to Northern Ireland and Norway and all transmission links to the rest of GB across B6 were removed. After calculating the LOLE in this new base case, we conducted a stress test. We also stress test with low VRES power^[13] and examine the additional capacity required to reduce LOLE to the 3-hour GB reliability standard.

Figure 16 LOLE of self-sufficient Scotland system in base case, low renewable output stress case and with additional firm capacities

The changes in level of capacity adequacy for a self-sufficient Scotland is given in Figure 16. Violation of the 3 hours GB standard occurs in the base case in the years 2025 and 2030, but the LOLE is less than 0.18 hours in 2035 and decreases in the following years. Figure 16 also shows the additional firm capacity needed to reduce the LOLE in 2030 to within the minimum required 3 hours, and to a more conservative range, for example, the 0.3 hours reported in the 2022 Winter Outlook^[14].

To achieve LOLE of 3 or 0.3 hours an additional 250 MW or 1000 MW equivalent firm capacity is needed respectively. Several alternative supply types can each provide an equivalent (de-rated) 250 MW of additional firm capacity:

• 274 MW installed capacity of CCGT with CSS.
• 380 MW battery storage 3 hours storage duration of 1140 MWh.
• 1,553 MW of installed capacity of offshore wind.

For 1000 MW additional firm capacity:

• 1,095 MW installed capacity of CCGT with CCS.
• 1,510 MW battery storage with 3 hours storage duration of 4,530 MWh.
• 6,211 MW of installed capacity of offshore wind.

The increase in offshore wind capacity in the base case is much higher than the additional installed capacity of wind required above. Therefore, as shown in Figure 17, the LOLE in 2035 is well within the acceptable range.

In a self-sufficient Scotland the share of wind in the total supply mix becomes more significant. Under the low VRES power output stress test, the LOLE increases to 6.8 hours in 2025 and 5.6 in 2030 but decreases to 0.32 hours in 2035 and reduces further in 2040 and 2045. The low LOLE in 2035 is due to a 25,000 MW increase in installed wind capacity from 2030.

Even after scaling down to 20% of VRES potential power output, there is still enough contribution from wind generation to serve the peak demand. Increases in biomass, hydrogen, and pumped storage capacity in 2040 and 2050 make non-variable supply alone sufficient to meet peak demand, further reducing the LOLE in the later years under the low VRES stress case. With 400 MW additional firm capacity can bring the LOLE to within 3 hours in 2025 and 2030. This is 150 MW more than is needed in the self-sufficient base case.

Black start capability

Removing interconnections and links to England may result in the loss of access to generators that are capable of providing black start. However, it does not necessarily imply that the black start capacity in Scotland is insufficient. The System Transformation scenario projects a significant increase in the capacity of hydro, battery storage, and pump-hydro storage in Scotland, which offer good black start capabilities. These sources have a combined capacity of 4,368 MW in 2030, which will increase to 6,023 MW in 2045, accounting for more than half of peak demand. Whether these assets are sufficient for black start depends on conducting simulations or tests of the system under various scenarios. It is also crucial to regularly review and update the black start procedures to ensure that they remain effective and relevant.

Low capacity and high demand scenario

We further tested the system, modifying the base case (System Transformation) scenario by removing future thermal power plants (i.e., hydrogen, gas and biomass CCS); using the more conservative ETYS21 [7] assumptions on B6 boundary expansion; and increasing peak demand to those in the Consumer Transformation Scenario. Table 4 shows the resulting modifications to the base case (see Appendix 12.18 for full dataset). We then show results for the de-rated system margin, LOLE, stress tests, and imports and exports.

Table 4 Modifications to System Transformation Base Case for the low capacity and high demand scenario
(Base Case capacities in brackets)

De-rated system margin

In the low capacity and high demand scenario, the de-rated system margin increases from 1,400 MW in 2025 to 4,500 MW in 2045, with a decrease in 2030 due to the assumed closure of all gas and nuclear generation in Scotland between 2025 and 2030. In the base case scenario, the gas CCS generation would have provided an additional de-rated capacity of approximately 1,600 MW in 2045.

The de-rated margin as a percentage of peak demand under the low capacity and high demand scenario between 2025 and 2045 is on average 32%. This is lower than the average 90% under the original base case scenario.

Figure 17 Installed firm generation capacity (GW) in Scotland under the low capacity and high demand scenario.

Loss of load expectation

Figure 18 LOLE results for low capacity and high demand scenario in Scotland from 2021 – 2045. GB Reliability standard 3hrs/y

The LOLE of the low capacity and high demand scenario, as illustrated in Figure 18, is considerably higher than the base case scenario (Figure 9) in all future years.

The year 2030 shows a significant increase in LOLE due to the closure of all gas and nuclear power stations, resulting in a LOLE of 6.3 hours/year which is higher than the GB reliability standard of 3 hours/year. Potential options for addressing this include keeping gas generation running for additional years while waiting for further renewable generation deployment or incentivising the development of additional storage and renewable generation before 2030.

By 2035 the subsequent strong growth of renewable generation capacity brings the LOLE back below the GB reliability standard. This is particularly due to an additional offshore capacity of approximately 17,300 MW from 2030 to 2035. As wind generation and storage capacity continue to increase, LOLE drops further from 2 hours in 2035 to 1.2 hours in 2045.

The lowest LOLE in the low capacity and high demand scenario is 1.2 hours/year in 2045, while in the original base case scenario, it is 0.0001 hours/year. This difference can be attributed to the exclusion of natural gas, hydrogen, and biomass, as well as higher demand. LOLE after 2030 in the low capacity and high demand scenario is relatively high compared to historical Scottish LOLE, such as 0.108 hrs/year in 2021. While this shows an increased risk of interruption to supply, it does not necessarily imply that such a shortage event will occur as it is still below the GB reliability standard.

Security of supply for the stress tests

Figure 19 LOLE for Scotland in the stress test cases under the low capacity and high demand scenario (2025–2045). GB Reliability standard 3hrs/y. LOLE 0.108 hrs/y of 2021 Scottish system

Except for the year of 2030 and the case of B6 failure in 2030-2045, all stress tests are within the GB reliability standard of three hours per year, but still greatly exceed the historical Scottish and GB LOLE in 2021, as presented in Figure 19. The disconnection from the rest of the GB stress test as illustrated using the ‘B6 Failure’ case has the most significant impact on the security of supply as measured by LOLE, far more than other test cases. LOLE of the other stress test cases are not significantly different from each other, with the offshore wind farm failure test highest, followed by unavailable interconnectors. This suggests that maintaining capacity adequacy in Scotland is highly dependent on imports from the rest of GB in this scenario.

The role of the B6 connecting Scotland to the rest of GB is more significant for security of supply in the low capacity and high demand scenario compared to the base case (System Transformation) scenario. The import capacity capability to Scotland across the B6 boundary is the main supply source after the renewable generation capacity in Scotland. In contrast, in the base case scenario, there is considerable capacity of CCS gas, biomass, and hydrogen generation, along with the B6 import capability, which can contribute to the security of supply.

Imports and exports

Imports (from rest of GB to Scotland) are higher and exports (from Scotland to rest of GB) are lower for the low capacity and high demand scenario compared to the base case scenario. This trend is consistent to 2045, which is shown in Figure 20 for imports and Figure 21 for exports. Over the year both scenarios have net exports of power across the B6 boundary. These results are due to the decreased generation and B6 boundary transfer capacity, and further highlight the greater importance of the B6 boundary in the low capacity and high demand scenario for security of supply.

Figure 20 B6 monthly import in 2045 under the base case and low capacity and high demand scenario

Figure 21 B6 monthly export in 2045 under the base case and low capacity and high demand scenario

Figure 22 shows the import and exports for the stress tests for the low capacity and high demand scenario. There is a reduced level of exports in these stress periods compared to the System Transformation base case, due to the lower generation capacity from hydrogen, gas CCS, and biomass. The greater reliance on VRES and the B6 boundary is highlighted by the high levels of import required for the low RES output stress test.

Figure 22 Import and exports in 2045 for 6-day period for stress tests in low capacity and high demand scenario

Conclusions

Lessons learned from national and regional electricity systems operating with close to 100% renewable energy sources:

• Several national and regional electricity systems operate at, or close to, 100% renewable electricity. However, these countries typically rely on dispatchable (non-VRE) renewable sources such as hydropower and storage reservoirs to generate and store electricity. These dispatchable renewable resources are only available at the required scale in a few countries. In Scotland, the most available renewable resource is wind, which is a variable source of energy.
• There are fewer examples of national electricity systems that operate with a high proportion of variable wind and solar energy shares. Denmark has the highest overall share of renewable electricity at 84%, with a high proportion from variable renewable sources and wind at 60% of total electricity production.
• Scotland has high wind generation, which makes up around 49% of total electricity generation, and relies on imports and exports with the rest of GB. It is most closely comparable to Denmark, which also makes extensive use of connection to neighbouring countries.

Changes to electricity market arrangements:

• Current GB electricity market arrangements are not suited to the net zero transition and potential reforms have been set out, which can enable a fully decarbonised electricity system by 2035. It is too early in the process to see a path for which reforms will be implemented and specify the impact they will have on security of supply.
• Splitting the wholesale market could improve the long-term sustainability of investing in renewable power in Scotland. However, it is possible that other reform proposals can provide the benefits outlined, and there could be a lack of additionality.
• Locational pricing might have the impact of depressing prices received by generators in Scotland as locational prices could be higher in England than in Scotland. Wind farms may require additional subsidy to be built in Scotland under locational pricing.
• A potential enhanced capacity market should take account of the issues specific to Scotland, while the Scottish Government should be an important stakeholder in strategic reserve decisions.

Technology pathway to net zero in Scotland in 2045:

• We have analysed the technology pathway according to the System Transformation scenario out to 2045 for Scotland. We found that security of supply metrics for Scotland in this scenario is well within the current GB reliability standards and comparable to current levels.
• There will be a reduction in traditional firm generation capacities (no nuclear and CCGT power plant generation capacity reduced when changing to CCS technology). However, these losses are offset by vast increases in wind and solar installed capacity, which can still provide security of supply, as well as increasing low-carbon firm generation capacity in the form of biomass, hydrogen and CCGT, with CCS power plants closer to 2045. Security of supply is further enhanced by the installation of battery, pumped hydro, liquid air and compressed air energy storage.
• Peak demand in Scotland is expected to rise to around 9,000 MW by 2045 but the de-rated system margin still increases from 2,200 MW in 2025 up to 12,200 MW in 2045, which shows there is sufficient firm generation. This was further verified by power dispatch simulation.
• The future Scottish electricity system has security of supply under the System Transformation scenario, but this cannot be directly assumed for the rest of GB supply and demand will likely continue to be balanced at GB-level by National Grid as the energy system operator. Therefore, while the generation capacity in Scotland may seem excessive in the context of security of supply, it will be utilised to decarbonise the rest of GB’s electrical system.
• We have further tested the future Scottish electricity system by modifying the System Transformation scenario: removing future thermal power plants; using more conservative B6 boundary expansion assumptions; and increasing peak demand. In this low capacity and high demand scenario security of supply in 2030 is worse (LOLE of 6.3 hours/year) than the GB reliability standard (LOLE of 3 hours/year).
• Beyond 2030 security of supply increases in the low capacity and high demand scenario but is relatively high compared to historical Scottish security of supply.
• Except for the year of 2030 and B6 failure in 2030-2045, all stress tests are within the GB reliability standard of three hours per year, but still greatly exceed the historical Scottish and GB security of supply in 2021.

Imports and exports between Scotland and the rest of GB:

• The System Transformation scenario requires a four-fold increase in transfer capability between Scotland and the rest of GB, from 6,100 MW in 2021 to 24,700 MW in 2045.
• Scotland will continue to be a net exporter to the rest of GB, and both total and net exports will increase. There are periods when Scotland will import only because it is economic to do so, rather than due to lack of local supply. There will be an increase in the level of import from the rest of GB due to increased demand coupled with the increased reliance on wind power generation.
• A period of low wind and solar generation has the largest impact on imports and exports from/to Scotland, followed by offshore wind farm failures. This highlights the importance of wind power generation in the future Scotland electricity system.
• Problems with interconnectors to Northern Ireland and Norway have the next biggest impact, but this will likely be more impactful if we see larger increases in interconnector capacity. Battery failure and gas supply issues have minimal impact on the imports and exports in the modelled period.
• Imports from rest of GB to Scotland are higher and exports from Scotland to rest of GB are lower for the low capacity and high demand scenario than for the System Transformation scenario. High levels of import are required for the low RES output stress test, illustrating the greater reliance on VRES and the B6 boundary in this scenario.

A self-sufficient Scotland:

• A self-sufficient Scotland with no connection to the rest of GB and no interconnector capacity to Northern Ireland or Norway was found to violate the 3 hours GB reliability standard in the years 2025 and 2030. However, by 2035 the reliability is within historical values and decreases in the following years.
• We find 250 MW and 1000 MW of additional equivalent firm capacity is needed in 2025 and 2030 to meet the reliability standard of 3 hours or recent values of 0.3 hours respectively. This can be achieved with the addition of 1,553 MW (to meet 3 hours) and 6,211 MW (to meet 0.3 hour) of installed capacity of offshore wind.
• The projected system beyond 2040 can meet reliability standards even after scaling down wind and solar generation to 20% of its potential output around the peak demand period. 400 MW additional equivalent firm capacity can bring the reliability standard to within 3 hours in 2025 and 2030, which is only 150 MW more than is needed in the self-sufficient System Transformation base case.

References

Appendices

2022/23 Winter Outlook

The 2022/23 winter outlook was developed amid unprecedented volatility in energy markets and concerns around shortfalls in gas supply. Additional scenarios were added to explore the potential impact of reductions in available electrical capacity from gas power plants and import capability through interconnectors. The National Grid report found that under the base case that there will be adequate security of supply with a de-rated margin of 3,700 MW (6.3%) in GB system which is in line with recent years (see Figure 23).

Two additional scenarios were presented in the 2022/23 winter outlook: 1) no electrical imports from continental Europe (Ireland and Norway interconnectors remained available); and 2) in addition to this, 10GW of CCGT being unavailable. Scenario 2 led to security of supply concerns and as a result 2GW of coal power plants and a 2GW novel demand flexibility service were brought into contingency planning.

Figure 23 De-rated margins from National Grid’s recent Winter Outlooks showing the figures for the Winter Outlook 22/23 are in line with historical margins

Ancillary services and system operability

Ancillary services are essential for ensuring the stability and reliability of power system operations, as they maintain frequency and voltage within acceptable ranges and prevent disruptions and blackouts. Unlike fossil-fuel generators, wind turbines and PV panels don’t provide the same level of inertia required to stabilise the system frequency changes following a loss of generation or demand. Ancillary services are not within the scope of the report but are important in understanding the impact of the changing electricity mix on power system operability. To compensate for the lack of inertia in renewable energy sources, modern wind turbines can be equipped with power electronics and control systems that provide synthetic or virtual inertia to the grid. Energy storage systems and other advanced grid technologies can also help balance the system and maintain stability.

National electricity systems with near 100% renewable

Several national electricity systems in the world already operate with, or close to, 100% renewable electricity. For example, Iceland generates all its electricity from either geothermal or hydropower. Other countries with high share of renewable generation include Paraguay (99%), Norway (98%), Uruguay (95%), and Costa Rica (93%) [23] [24]. Despite these impressive levels of renewable generation, there is still some non-renewable electricity generation in each of these countries. In Paraguay, small-scale industrial power plants using sources such as oil, natural gas, and coal contribute to the non-renewable part. In Norway, thermal power plants are the primary source of non-renewable electricity. Both Uruguay and Costa Rica rely on oil-fuelled power plants to support renewables.

The common feature of these countries is that generation from hydropower plants and storage reservoirs dominates the renewable supply. In Norway, many hydropower plants have storage reservoirs. With reservoirs, hydropower production can be adjusted within the constraints set by the watercourse itself. Therefore, they have flexibility which makes it possible to follow the variation of demands, even during periods when there is little rainfall or river inflow.

Blåsjø, Norway’s largest reservoir, has a capacity of 7.8 TWh^[15], which is equivalent to three years’ normal river inflow, and can store water for a long period to meet high electricity demand during the heating season in winter or support electricity supply in a dry year [25]. In addition, other hydropower plants with small reservoirs offer short-term flexibility, and can be operated to provide both baseload and peak load due to their ability to be shut down and started up at short notice. Overall, these reservoir storages help to smooth out production over days, weeks, months or between years.

Reservoirs also make it possible to manage output to maximise income through both export and import power to or from neighbouring countries when there is a price difference. Electricity is exchanged with Sweden, Denmark, and Finland through an integrated market called Nord Pool, which is in turn connected to the wider European market through interconnectors to the UK, Netherlands, Germany, the Baltic states, Poland, and Russia

More than 75% of Norway’s renewable generation is dispatchable [26], which ensures the electricity system operates with high levels of reliability and security.

Electricity systems with very high VRE share

The leading national electricity systems with high shares of wind generation (VRE) are Denmark (56% of total electricity production from wind in 2020), Uruguay (40%), Lithuania (36%), Ireland (35%), the UK (24%), Portugal and Germany (both around 23%). For solar energy, the top countries are Honduras (12.9%), Australia (10.7%) and Germany (9.7%) [23] [24] [26].

Countries which rely on VRE have lower overall shares of renewable electricity than countries that benefit from abundant hydropower resources. Of the countries with high VRE share, Denmark has the highest overall share of non-fossil fuel generation at 84%, including 20% from biofuel electricity which is mainly produced in CHPs, and 4% from Solar PV. Since biofuel CHP can be dispatchable, it provides valuable flexibility in helping the operation of the Danish system with over 50% VRE.

The Danish Energy Agency has summarized the successful measures it has implemented to increase the share of variable renewable energy (VRE) while maintaining high security of supply over the past two decades. During this time, various technical and institutional solutions were introduced, as shown Figure 24:

• 2000-2009 (VRE shares <20%): Limited investments in flexibility were made, but the supply was met through more flexible operation of existing thermal power plants and better utilization of interconnectors. Flexible thermal power plants, interconnectors, and forecasting and scheduling systems were the primary sources of flexibility.
• 2010-2015 (VRE shares 20-44%): As the VRE share grew, larger investments in flexibility were made. Solutions included complete turbine bypass, electric boilers, heat pumps, and joining the Nordic power exchange for cross-border trading. The ability for VRE to self-balance was improved through the European cross-border intraday market.
• 2016-2020 (VRE shares 44-50%) and beyond: The focus shifted towards demand-side flexibility and increased sector coupling. Aggregators were introduced to encourage active consumer participation in balancing the system, and the market remained the main driver of flexibility.

The importance of different categories of power system flexibility in Figure 24 has varied over time for integrating renewables in Denmark. The generation side was the main source of flexibility until 2020, but these measures alone will not be able to accommodate the increasing amounts of VRE economically or technically. To continuously develop towards a 100% renewable Danish power system by 2030, Denmark sees increased sector coupling and demand-side flexibility as key providers of new flexibility measures in the future [27]. The focus of sector coupling has also changed from power and heating generation to using surplus electricity and decarbonizing difficult to electrify sectors.

Figure 24 Flexibility measures being implemented in different periods in Denmark power system. Note this indicates where new efforts are being focussed – e.g., interconnectors are still widely used after 2020

Regional electricity systems with near 100% renewable

In some countries, annual renewable energy production from certain regions is already reaching or exceeding local demand, e.g., Mecklenburg-Vorpommern, Schleswig-Hostein in Germany, Orkney in Scotland, and Samsø in Denmark.

The challenge Orkney faces is an interesting example of a regional electricity system with more than 100% VRE. Despite the excessive locally generated green energy (more than 130% over its local annual electricity demand), there are still periods when the wind speed is low, and Orkney needs to import electricity from the UK mainland. To find a non-fossil fuel based solution to tackle the issue of intermittency, a recent smart grid demonstration project – ReFLEX (Responsive Flexibility) Orkney [28] – has set the aim of fully decarbonising Orkney by 2030 through deploying smart controlled battery systems and electric vehicles, and enhancing demand response by interlinking electricity, heat and transport assets.

Background on proposals in REMA

Current arrangements

Under current electricity market arrangements electricity is traded through bilateral long-term contracts, and short-term power exchange marketplaces. Generators sell electricity to end-users often through energy retailers. Generators and suppliers then declare how much electricity they are expecting to generate or use to NG ESO. Based on these declarations a national electricity price is formed which informs power exchange markets on the prices to sell electricity in the short-term. This national price formation is often what is referred to as the wholesale price.

Generators and end-users are free to trade anywhere across Great Britain. For example, a wind farm in the north of Scotland can sell its generated electricity to an industrial end-user in London as easily as it can sell to supply the houses in a nearby town. However, these trades do not account for spatial considerations such as limits in the transmission network. Generators and demands must inform National Grid of their actions on a half-hour basis, where the balancing mechanism is used to ensure balance between supply and end-users. The balancing mechanism may ask generators to increase or reduce, and/or end-users to reduce, in return for additional payments. National Grid also procure additional services in ancillary markets to ensure safe and reliable operation of the grid. There are increasing costs to use the balancing mechanism as the proportion of renewables increases (Figure 25). This is a driving factor in the need for new market arrangements.

Figure 25 Left hand graph shows rising costs of curtailment of wind farms. Right hand graph shows points which represent the years from 2010 to 2020 relating to wind generation and annual cost, in addition to lines which plot out the cost of curtailment per MWh of wind energy produced. The points are rising through the years from £1/MWh to above £4/MWh showing that the cost of each MWh of curtailment is increasing.

Splitting the wholesale market

A proposal gaining traction is splitting of the wholesale market. The idea is to decouple low marginal cost renewable power from high marginal cost dispatchable power, e.g., by splitting the market based on technology type into separate markets for variable and firm power. This avoids the wholesale market price primarily being set by gas prices. It could also help stabilise prices in future when there is a greater proportion of renewable power, and prices would otherwise swing between high prices set by gas generation and low prices set by high renewable output.

Potential advantages:

• Encourage investment in renewable power by helping alleviate issues of price volatility and price cannibalisation^[16].
• Incentivise flexibility as more demands would look to buy from the lower cost, but less available, ‘variable’ market. Additionally, flexible technologies like batteries could benefit from access to both markets and shifting demand for price difference opportunities.
• Reduce need for long-term government support, e.g., through contracts for difference (discussed later).

Potential disadvantages:

• Uncertain implementation as this type of market has not been adopted by any major power market, and many variants have been suggested.
• Competition with other reform proposals as most of the benefits can likely be delivered through other ways.
• Lack of protection for end-users to the complexity and increased cost of not engaging with both markets.
• Lower liquidity (volumes which can be traded) in each individual market resulting in reduced competition between technologies.

Splitting the wholesale market could improve the long-term sustainability of investing in renewable power in Scotland. There would be a long-term market in which profits can be made, with more stable prices, and a reduced reliance on government support. However, it is possible that other reform proposals can provide the benefits outlined, and there could be a lack of additionality.

The wholesale market price is currently set by the last generator to turn on to meet demand. This is determined by the free market nature of the GB electricity market where bilateral trades can be made between any generator and demand, or through short-term power exchange markets. The flexibility of the current power system is primarily through flexing gas-fired power plants which means that these are the last generator to meet demand. Therefore, the wholesale electricity price is usually tied to gas prices.

As the proportion of electricity generation from wind and solar sources increases, there have been increasing concerns around the lack of effect of the high proportion of low-marginal cost renewable power on electricity prices. This non-effect on prices is a consequence of the liberalized electricity market. This has led to calls for reform on the wholesale market to better suit the net zero transition and to provide investment and operational signals to support the roll-out of mass renewable power. The current gas crisis with huge increases in the prices of gas has exacerbated this issue, increasing the voices supporting reform.

An alternative to the wholesale price formation is to move to pay-as-bid pricing where generators would receive what they bid, rather than the highest bid. This could decouple gas prices and electricity prices. However, it is likely that generators will bid higher than marginal cost to close the gap to the highest bid, resulting in a market price just below the price of electricity produced by gas power plants. Market intervention by limiting bids could mitigate this, but it is unclear how this could be implemented in practice.

Locational pricing

Locational pricing sets prices at a more granular spatial level than current national pricing. In nodal pricing there are prices at each location in the transmission network; and in zonal pricing the network is split into zones, each with a price, where it is assumed there are negligible network constraints. In both structures the prices incorporate the physical constraints of the network and includes both the cost of the energy and the cost of delivering it.

Potential benefits of locational pricing:

• Reduce whole system costs by incorporating network costs, such as the balancing mechanism, into wholesale costs.
• Nodal system would resolve network congestion inherently and remove the additional costs of the balancing mechanism. Zonal pricing would still likely require a balancing mechanism but could substantially lower costs.
• Strong signal for investing in technologies in the locations which can reduce whole system costs.
• More efficient network investment, as greater integration of network constraints in the electricity markets.

Potential disadvantages:

• Mismatch between where the greatest renewable energy sources are and where the congestion issues are for the network. For example, offshore wind offers greater capacity factors but is physically on the edge of the network.
• Potential for increased payments to existing CfD contracts as these generators are likely already existing in areas where the locational price will be lower than national price.
• Benefits of locational pricing can be greater for fossil fuel power plants (for issues such as ramp up rates and start-up costs), but with the net zero transition these benefits will be diminished.
• Greater consumer exposure based on location.
• Low liquidity in zones or nodes.
• Greater infrastructure requirements to manage the more complex system.
• For zonal pricing there is uncertainty in defining zonal areas and actual returns.

Scottish Renewables has spoken out against location pricing with a central argument being the difference in planning systems across the UK with different stakeholders holding varying interests [29]. They argue for reform of the TNUoS, the current network charge, which is locational based, as an alternative.

There would be a large impact on the Scottish power system with reform to locational pricing. Scotland has substantial wind resource with a large proportion of onshore wind farms and with large capacities of offshore wind in the pipeline. Locational pricing might have the impact of depressing prices received by these generators as locational pricing could be higher in England than in Scotland. This is because the main network congestion is currently delivering renewable generation from Scotland to England.

The motivation of locational pricing is to encourage generators and flexibility operators to take account of the real physical constraints in the network. This can result in investing and operating in areas which have higher value to the whole system and should provide higher rewards for generation and flexibility technologies. This can lead to more efficient location of new resources and efficient expansion of the network. Generators are provided with an incentive to locate to areas of high demand to access higher electricity prices. It also incentivises increased demand in areas which high renewable resources, but lower existing demands (and therefore prices). Since new and recent renewable generation often use contracts for difference this needs to be accounted for in any locational pricing design. Nodal pricing has recently been advocated by the National Grid [30] and the Energy Systems Catapult [31].

There is also interest in extending the granularity to local markets at the distribution level where there is responsibility for a distribution network operator to balance a local market. These local markets would interface with the existing national wholesale market.

Contracts for difference

Contracts for Difference (CfD) is the primary mechanism currently used by the UK government to support deployment of mass low-carbon power. A CfD contract guarantees a ‘strike price’ for generation. When market prices are below the strike price generator income is topped up and when market prices are above the strike price generators must pay back into the scheme. The scheme has seen the cost of renewables drop, by providing long-term certainty which reduces the cost of capital, as well as attracting investors. Strike prices are set through competitive auctions via pots for different technologies with set levels of government support.

Reform of CfDs is being considered since a greater proportion of total generation could end up being CfD supported in the transition to a net zero energy system. This raises issues around the lack of incentives to operate flexibly, locate in areas which help the network, and in competition with other generation technologies. Potential reforms are centred around increasing market exposure, such as a strike range, as opposed to a single price, to increase market exposure, and topping up payments based on comparison to wholesale prices over a week rather the current method of comparing prices in each half-hour pricing period.

Revenue cap and floor

Revenue cap and floor contracts would guarantee generators a minimum revenue over a contracted period. Their application to generators is inspired by contracts offered to 11,000 MW of interconnectors. An advantage is guarantees to investors of minimum revenue levels which helps minimise risk. Generators then have the freedom to participate in all the different electricity markets and attempt to maximise revenue. A cap is also implemented which if revenue exceeds, then the difference is paid back to the government.

Flexibility

Flexibility in the current electricity system comes from dispatchable fossil fuel power stations which can respond to demand changes and variable output from renewable power sources. In the net zero transition there will be a need to increase low carbon flexibility technologies. This includes renewable generation which can respond in different timeframes; and storage including batteries and long duration storage (see CCC report for more details [32]). Compressed air energy storage, Hydrogen, interconnectors offering firm low carbon power from countries like France (nuclear) and Norway (hydro), and demand-side flexibility such as electric vehicles and heat pumps could all have a role.

The UK government currently envisions that flexibility should be incentivised through pricing signals in the wholesale and balancing markets. There have been proposals to ensure these signals better reflect the need of the whole energy system, and therefore ensure flexibility is built in the right locations:

• Revenue cap and floor (similar as for low-carbon generation described earlier) so that flexibility technologies can participate in the full range of markets, but with the safety net of a minimum revenue which can strengthen investor confidence and interest.
• Supplier obligation where suppliers are required to achieve a set target for procuring flexibility.
• Reforming the capacity market to encourage technologies with different flexible characteristics (e.g., response time, duration of response, and location).

Capacity adequacy

It is of vital importance that market arrangements enable secure investment in the required capacity to ensure that electricity supply and demand are matched, and the ‘lights do not go out’. This is most difficult to achieve in extreme cases, such as during demand peaks (often a winter peak) and, very importantly in future, during long periods of low wind. These periods are currently primarily met through fossil fuel power plants such as gas CCGTs. However, many of these power plants are set to retire in the transition to net zero. Additionally, low marginal cost renewable power will displace high marginal cost fossil fuel power plants in the wholesale markets reducing revenues for these firm sources of electricity.

Proposed reforms for capacity adequacy are:

• Enhanced capacity market: Currently, the capacity market is the mechanism for topping up revenues for generators who can provide capacity adequacy. However, the majority of support has gone towards fossil fuel generators, highlighting the need for mechanisms which support low-carbon firm capacity. An enhanced capacity market would target low-carbon technologies which can provide flexibility and support capacity adequacy. Essentially, the capacity market would become more targeted and selective. This could be done through separate auctions or multiple clearing prices, with a careful balance of avoiding target setting which can supress competition.
• Strategic reserve: In this proposal a central authority auctions for reserve capacity on top of the capacity which is built through other markets. This would essentially act as a backstop to ensure security of supply without further intervention in existing markets.
• Operability: A number of proposals for reform around operability have been put forward. Capacity adequacy is an issue related to ensuring that extreme cases which the market does not account for does not result in system failure. Operability is how these assets then perform to ensure power grid stability. These involve evolving the existing suite of ancillary markets to increase the level of low-carbon technologies.

The issue of capacity adequacy is important for the Scottish electricity system, particularly as Torness nuclear power plant is due to close, and the gas CCGT at Peterhead needs to change to carbon capture and storage technology to be compatible with the net zero future. A potential enhanced capacity market should take account of the issues specific to Scotland and this has been highlighted as location is a characteristic which has been described as important to consider.

Contracts for difference

The CfD looks set to continue as the primary support mechanism for the roll out of mass low-carbon power [15]. This means that renewables in the Scottish energy system will continue to receive long-term contracts to provide stable income. It has also been suggested that older renewable generators, previously supported through ROCs or independently, could be offered a CfD contract.

Revenue cap and floor

Revenue cap and floor contracts could accelerate the roll out of wind power in the Scottish electricity system, while also incentivising flexibility such as batteries. This option could help improve the security of supply for Scotland, but it is not clear if this option would perform better than CfDs.

Flexibility

In Scotland there is likely to be an increased need for flexibility given the increasingly high penetrations of VRE generation. Therefore, it is important that changes to electricity markets incentivise situating flexibility technologies in Scotland. Current markets are not suited to delivering the flexibility required and while there are options being explored, it is not clear that the proposed reforms will deliver the required levels of flexibility in Scotland.

Future Energy Scenarios

The FES is widely recognized as a comprehensive and authoritative source of information and analysis on the future of GB electricity system. The data released as part of FES22 includes regionalised breakdowns of generation capacity, storage capacity, and demand for each grid supply point^[17] and transmission network area. National Grid use a combined bottom-up and top-down modelling approach^[18], and a series of stakeholder engagements to determine the regional data [33]. The four scenarios in FES are:

• Leading the Way is the fastest credible decarbonisation pathway of the four scenarios and includes significant lifestyle change and a mixture of Hydrogen and electrification for heating.
• Consumer Transformation has a lower speed of decarbonisation than leading the way but includes high societal change with consumers willing to significantly change behaviour. This scenario assumes electrified heating, high energy efficiency, and demand side flexibility.
• System Transformation has the same speed of decarbonisation as Consumer Transformation but with fewer changes in consumer behaviour and higher reliance on system-level development. This scenario assumes Hydrogen for heating, lower energy efficiency, and supply side flexibility.
• Falling Short is the slowest credible decarbonisation pathway and the only scenario which falls short of net zero by 2050. It assumes minimal behaviour change and decarbonisation in only power and transport, not in heat.

Heat demand and Hydrogen in FES

The System Transformation scenario assumes that most heating is met by Hydrogen, which results in a lower peak demand than in Consumer Transformation (heating is primarily electrified) and Leading the Way (mixed approach to heating). It should be noted that this perspective is not consistent with the Scottish Government’s Hydrogen Action Plan [34], which states that Hydrogen is intended to support a portion of domestic heating systems while also having potential for various alternative market opportunities.

Despite this difference, both plans share similar levels of ambition in promoting Hydrogen production capacity and usage. The Hydrogen Action Plan for Scotland projects a renewable Hydrogen production capacity of 5 GW by 2030 and 25 GW by 2045 within Scotland, which is comparable to the projections in the System Transformation plan (6 GW by 2030 and 69 GW by 2045 for the entire UK). Hydrogen produced by electrolysers are assumed in FES to not operate during the peak demand period. This assumes large-scale infrastructure including Hydrogen storage is connected to a distribution network which can deliver Hydrogen to end users.

PyPSA-GB details

PyPSA-GB^[19] has been developed to simulate the GB power system in high spatial and temporal resolution for both historical and future years [16]. The data included in the model has been sourced from openly available datasets found online. Code for PyPSA-GB is written in Python and Jupyter Notebooks are used to showcase data, functionality, and analysis.

For the historical years, 2010-2020 inclusive, PyPSA-GB includes data on generators, marginal prices, demand, renewable power, and storage. Simulating historical years can provide insight into the operation of the GB power system, e.g., dispatch of thermal power plants and curtailed renewable generation. It is also useful in order to compare to historical data and build confidence in the model.

For future years, PyPSA-GB includes data to simulate future years based on National Grid’s FES2021 and FES2022 for all four scenarios which go up to 2050. Steady Progression represents business as usual with low level of both societal change and speed of decarbonisation and is the only scenario which fails to meet the net zero target. Leading the Way represents the highest speed of decarbonisation coupled with a high level of societal change. Consumer Transformation and System Transformation represent the same speed of decarbonisation, but Consumer Transformation requires higher level of societal change than System Transformation.

The power dispatch functionality utilises the open-source PyPSA (Python for Power Systems Analysis) to perform network-constrained linear optimal power flow calculations. PyPSA can calculate linear optimal power flow by least-cost optimisation of power plant and storage dispatch within network constraints, using the linear network equations, over several snapshots. In this study, models and data in PyPSA have been used: meshed multiply-connected AC and DC networks, with controllable converters between AC and DC networks; standard types for lines; conventional dispatchable generators; generators with time-varying power availability, such as wind and solar generators; storage units with efficiency losses; simple hydroelectricity with inflow and spillage. In this work simulations were carried out in hourly timesteps over a year.

Security of supply metric calculations

Listed below are the formulae for calculating loss-of-load expectation (LOLE), loss-of-load probability (LOLP) and de-rated system margin:

where the LOLP for a particular period is defined as the probability that available generation is unable to meet demand:

where X_t is the available generation and D_t is the system demand, both of which are random variables. A typical example for T and t is a time horizon of one year with periods of one hour.

The de-rated capacity margin measures the amount of excess supply above peak demand. De-rating means that the supply is adjusted to take account of the availability of plant, specific to each type of generation technology. The technology-specific de-rate factors are given in Table 5 and Table 6 [22] in Appendix 12.13.

De-rated system margin is used as a proxy for risk of loss of supply. It is calculated as the difference between the peak demand and the de-rated supply capacity. The de-rated supply capacity is calculated by scaling down installed capacity by the expected availability at peak demand, and by converting variable generation capacity using an equivalent firm capacity (EFC) factor. The EFC is a measure of the capacity adequacy contribution provided by wind and solar. It refers to the amount of power that a wind or solar farm can consistently deliver over time, which is useful to translate the variable output into an equivalent amount of firm capacity in the calculation of security of supply. EFC can be much lower than capacity factor, as the capacity factor reflects the average output of a wind farm, while the EFC reflects the reliability and consistency of that output. For example, the latest winter outlook, 16.1% is used as the EFC factor for wind generation.

GB supply under System Transformation

Figure 26 Plot of de-rated supply capacity, peak demand and supply margin of GB for System Transformation from 2025 – 2045

Figure 26 shows de-rated capacity and system margin results for the entire GB system, which includes the Scottish electricity system. The overall system margins of GB also vary in the future, peaking at 18% by 2035 after a rapid increase in generation capacity from 2025, and then falling back to 11% by 2045 when the rising demand catches up. It is evident from these results that the GB system margin is substantially less than that of the Scottish system alone. While the generation capacity in Scotland may seem excessive in the context of security of supply for only Scotland, it will be utilised to decarbonise and provide security of supply to the rest of GB.

Figure 27 shows power dispatch for all of GB for the System Transformation scenario and includes time of peak GB demand. The majority of generation is from variable renewable energy sources (VRES) – solar photovoltaics, wind offshore, and wind onshore – while nuclear slowly increases to the peak demand period. Firm generation – a combination of Hydrogen, CCS gas, hydro, and biomass and storage (pumped storage hydroelectric, batteries, compressed air, and liquid air) – are dispatched around the peak demand and at times of low VRES generation. It is notable that the period of highest use of firm generation and storage is at a period of low VRES and high demand which happens after the peak GB demand.

Figure 27 Power dispatch of whole of GB for System Transformation in 2045 over 2-day period, excluding interconnectors to Europe.

Security of supply stress tests

Base case

The base case shows the power dispatch for the System Transformation scenario over a 6-day period from 5 December to 10 December, and can be used as a comparison to the stress test power flow figures.

Figure 28: Power dispatch modelled over the 6-day period for base case.

Offshore wind farm failures

In security planning, the ability of an electrical power system to handle failure of its largest generator is tested. Historically this has been a large, centralised fossil fuel power plant. However, in 2045, the largest single generator in Scotland will be from the network of offshore wind farms.

Figure 29 Power dispatch modelled over the 6-day period the stress event of the failure of offshore wind farms.

Figure 29 is the power dispatch modelled over the 6-day stress event of the failure of offshore wind farms^[20]. The power dispatch shows use of hydrogen power plants which were not dispatched in the base case. It is notable that CCS gas is not dispatched. The reason hydrogen is dispatched first is due to modelling assumptions with the marginal cost of hydrogen being lower than CCS gas. Despite the dispatch of hydrogen there is still export to the rest of GB. The effect of the failure of offshore wind farms is increased use of hydrogen generation, storage discharging, and imports from the rest of GB.

Low VRES power output

Scotland will be increasingly reliant on VRE in the form of wind power. This stress test analyses how the electricity system copes with a prolonged period of low VRES power output.

Figure 30 Power dispatch modelled over the 6-day period the stress event of low-VRES power output. Not lower scale on GW y-axis than other power flow figures

Figure 30 is the power dispatch modelled over the 6-day period the stress event of low-VRES power output during the peak demand period. There are substantially more periods of import to make up for the reduction in renewable power generation in Scotland, while hydrogen and biomass power plants are at full output, aided by dispatch of all storage types (pumped storage, battery, compressed air, and liquid air). As with the offshore wind farm failure, there are still exports to the rest of GB, however this does result in periods when Scotland is a net importer of electricity.

Gas power generation in Scotland unavailable

Figure 31 Power dispatch modelled over the 6-day period for the stress event of unavailable gas power generation.

Figure 31 shows power dispatch modelled over the 6-day period for the stress event of gas power generation not being available in Scotland. This has a much smaller impact on power dispatch compared to the wind power issues of the previous two stress tests, even with the dispatchability of the CCS gas. This is because the CCS gas is 1,800 MW in 2045 compared to the 21,000 MW wind farm failure in the first stress test.

Interconnectors to NI and Norway unavailable

Figure 32 Power dispatch modelled over the 6-day period the stress event of interconnector to Norway and Northern Ireland being unavailable.

Figure 32 shows the power dispatch for the stress event where both the interconnectors to Norway and Northern Ireland are unavailable. This results in some wind generation being reduced, or curtailed, as there is less capacity to export.

Connection to rest of GB unavailable

There will be more reliance on the connection between Scotland and the rest of GB in the future to accommodate increases in power flow. Increased imports to Scotland will be required to meet demand when there is low wind generation, and exports to the rest of GB will increase due to large installed capacities of wind generation in Scotland and to decarbonise demands in the rest of GB.

Figure 33 Power dispatch modelled over the 6-day period the stress event of no connection between Scotland the rest of GB

Figure 33 shows the power dispatch modelled over the 6-day period for the event of no connection at all between Scotland and the rest of GB. This results in power dispatch which is almost entirely reliant on wind generation coupled with charging and discharging of pumped storage plus other storage types. Wind generation over this period is enough to meet the demand of Scotland, however, there is no ability to export to the rest of GB which means that lots of potential wind generation is curtailed.

Storage failures

Flexibility in the electricity system will increasingly come from storage, as opposed to the dispatchability of traditional fossil fuel power plants. While large, centralised fossil fuel power plants offer a single source of failure, storage technology such as batteries, pumped hydro, compressed air energy storage, and liquid air energy storage will likely be distributed through the electrical network in a larger number of individual units. Therefore, storage will likely offer a higher degree of reliability, but this may be offset by uncertainty around the state of charge, i.e., how much electricity can be discharged from the storage unit.

Figure 34 Power dispatch modelled over the 6-day period the stress event of no battery storage in Scotland.

Figure 34 shows the power dispatch modelled for the stress event of no battery storage in Scotland. This has minimal impact compared to the base case but does decrease the utilisation of wind generation resulting in less import and export. The pumped hydro appears suited to making up for the loss of battery storage.

Security of supply data requirements

Probabilistic data is required to calculate the LOLE, LOLP, and de-rated system margin. An important input is the probability that each generator will be available at any time. This is characterised by the rate at which a unit is likely to experience forced outages, and will vary between generators depending on the technology, age and operating regime. With the outage rate (or given as availability factor = 1 – outage rate), the probability distribution for available supply capacity can be constructed using the Capacity Outage Probability Table method developed by Billinton and Allan [35].

The approach taken in this report is to use generation data from the FES22 scenario for technology capacities, and to use expected availability factors assumed in the latest 2022 National Grid’s Winter Outlook [22] and National Grid’s ESO Electricity Capacity Report [21]. This data of outage rate per type is summarised in Table 5. The de-rating factor applied for duration-limited storage (i.e. battery), is directly linked to the duration, as shown in Table 6. For instance, a storage system with a power rating of 100MW and a duration of 3 hours (equivalent to an energy capacity of 300MWh) would have a de-rating factor of 66.18%. The aggregate cumulative distribution function (cdf) for available generation, using 2030 in the System Transformation scenario as an example, are displayed in Figure 35.

Table 5 Generation de-rate factors and outage rate used in this study

Table 6 De-rate factors for duration limited storage

Figure 35: Cumulative distribution function (CDF) for available generation in 2030 ST scenario. For illustrative purposes, an indictive peak demand of 10 GW is shown as a vertical line, and probability for not meeting the level of demand is 0.25. For peak demand around 5.5 GW, which is what is forecasted in Scotland, the probability for not meeting the level of demand would be statistically zero based on the CDF curve.

Data for Scotland under Leading the Way