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Johnson Matthey Technol. Rev., 2020, 64, (3), 307


Electric Vehicles and Their Role in the Energy System

Decarbonising transport and electricity in Great Britain


Article Synopsis

Electric vehicles (EVs) can help decarbonise both transport and electricity supply. This is both via reduced tailpipe emissions and due to the flexibility in charge and discharge that EV batteries can offer to the electricity system. For example, smart charging of EVs could enable the storage of roughly one fifth of the solar generation of Great Britain for when this energy is needed. However, to do this, the market needs to align vehicle charging behaviour to complement renewable generation and meet system needs.

1. Introduction

The energy system is rapidly transforming, driven by political, economic, environmental, technological and consumer pressures. These changes include the rise in renewable electricity generation and the use of EVs and substantial further changes will need to take place for the UK to meet its decarbonisation goals by 2050. As the electricity system operator (ESO) for Great Britain, National Grid ESO is responsible for moving electricity safely, reliably and efficiently through the system. Great Britain refers to England, Scotland and Wales excluding Northern Ireland. National Grid ESO operates the electricity system in Great Britain only, its Future Energy Scenarios (FES) publication covers Great Britain in detail and makes fewer assumptions about Northern Ireland.

National Grid Electricity Transmission (NGET), UK, a legally separate company to the ESO, owns the transmission network of pylons and cables that are used to transport high voltage electricity throughout the country. Smaller regional operators, known as distribution network operators (DNOs), reduce the voltage and take electricity to people’s homes. The ESO is responsible for balancing the system and ensuring that supply always matches demand so that homes and businesses always have access to power (Figure 1).

Fig. 1.

National Grid structure, showing the legal separation and relationships between the National Grid ESO, NGET and National Grid Gas (NGG)

National Grid structure, showing the legal separation and relationships between the National Grid ESO, NGET and National Grid Gas (NGG)

National Grid ESO publishes a FES document for Great Britain annually (1), setting out a range of credible scenarios for how the energy system might develop over the next 30 years. This helps us to better understand the range of uncertainties for the future of energy in the country. As ESO, we are in a privileged position that enables us to draw on insight and data that cut across both electricity and gas in developing FES. We develop a whole system view of energy, helping the industry to understand how low-carbon solutions can be delivered reliably and affordably for the consumer of the future. FES is the starting point for planning long-term regulated investment in gas and electricity systems and is also used by stakeholders as a sound consistent reference point for a range of different published reports. This article references data from FES 2019. This was published in July 2019 and based on analysis conducted before the UK’s decarbonisation target was changed from an 80% reduction by 2050 to meeting net zero. Analysis in FES 2020, launched 27th July, suggests that meeting net zero will only increase the importance of electricity system flexibility and the ability of electric vehicles to facilitate decarbonisation.

Climate change is one of the biggest challenges facing the world and decarbonising our energy system is a major part of responding to this. The UK was the first country to set a legally binding emissions reduction target through the Climate Change Act 2008; this legislated for an 80% reduction in greenhouse gas emissions by 2050 from a 1990 baseline (2). In June 2019 the parliament revised this target to require the UK to become net zero by 2050 in line with a recommendation from the Committee on Climate Change, UK. Net zero means any greenhouse gas emissions would be balanced by schemes to offset an equivalent amount of carbon from the atmosphere, such as planting trees or using technology like bioenergy carbon capture and storage (BECCS).

Transport is clearly a major area of change in the energy system. As take-up of electric cars increases, this shifts energy demand from oil (to produce petrol and diesel) to electricity (to charge car batteries). When combined with the decarbonisation of the electricity system, we will see carbon emissions from transport reduce dramatically. This shift increases demand on the electricity system and may present additional challenges depending on when and where these vehicles are charged. One of the key messages from FES 2019 was that EVs can help decarbonise both transport and electricity supply for Great Britain. This is through the use of smart charging (managing the times vehicles are charged so this avoids existing peak demand times on the network) and through vehicle-to-grid (V2G), where electricity stored in the battery of an EV can be supplied back into the network through a two-way V2G enabled charger. This article explores the potential for electric cars to enable the decarbonisation transition in greater detail.

2. Change in the Energy System

This section explores the change in the energy system that has taken place over the last decade and how we expect it to change in future. This encompasses the rapid rate of decarbonisation in the electricity sector we have seen since 2010 and the ongoing disruption in the transport sector.

2.1 Growth in Electric Vehicles

In July 2018 the UK government’s Road to Zero Strategy was announced, including the ambition to see at least half of new cars to be ultra low emission vehicles (ULEV) by 2030 (3). ULEVs are vehicles that emit less than 75 g of carbon dioxide from the tailpipe for every kilometre travelled; in practice, the term typically refers to battery EV (BEV), plug-in hybrid EV (PHEV) and fuel cell EVs. This built on the government’s commitment to “end the sale of new conventional petrol and diesel cars and vans by 2040”.

There are over 200,000 ULEVs in the UK as of the second quarter of 2019 (4) and while total ULEV registrations are still low, this is growing rapidly for several reasons, including government tax incentives and consumer appetite for decarbonisation. 2019 saw an 87% year on year increase in BEV registrations and a corresponding decrease in PHEV registrations due to subsidy changes (5). In this article the term EV is used to refer to both BEVs and PHEVs; currently EV stock is split between these two types, however in 2050 we expect most cars to be BEVs.

To model the uptake of various road transport types and fuels in our 2019 FES we utilise a total cost of ownership model. Assumptions on the increase and decrease of various factors including battery costs, fuel costs, vehicle efficiency and subsidies available for different scenarios feed into this model. The uptake rates for the different scenarios, in relation to the expected sales projections for all vehicles (determined by the total cost of ownership and the rate at which older vehicles are scrapped) gives the expected number of low carbon vehicles on the road (Table I).

Table I

Electric Vehicle Growth Projections (1)

2019 Scenario modelling
2030 2050
Number of electric cars 209,000 Minimum 2.3 million 31.3 million

Maximum 11.5 million 33.6 million

The slowest growth scenario in FES projects only 2.3 million EVs to be owned in 2030 compared to a maximum of 11.5 million EVs in 2030 in the highest growth scenario. This represents 6.8% and 35% of cars being electric respectively in each scenario. By 2050 we expect almost all cars to be electric in all scenarios, although some petrol and diesel fuelled vans and heavy goods vehicles (HGVs) still exist in the slower decarbonisation scenarios. Although this shift towards EVs will cause an increase in overall electrical energy demand, the greater challenge lies in charging; i.e. where, when and how these vehicles are charged.

2.2 How the Grid Decarbonises

Traditionally the grid has been supplied by a relatively small number of large generators, primarily coal, gas and nuclear power stations. The energy system is transitioning from this centralised system where there were under one hundred generators primarily connected to the transmission network with flexible fossil fuel plant to help meet demand peaks, to the current state where there are thousands of smaller decentralised generators such as wind and solar farms mainly connected to the distribution network. Over the past 10 years this growth in renewables has led to new challenges in system operation, with wind and solar generation presenting issues due to generation variability.

Significant progress has been made decarbonising the electricity system since 2010 thanks to this growth in renewable generation. The carbon intensity of electricity is a measure of the level of CO2 emissions that are produced per kilowatt hour of electricity consumed. The average carbon intensity of electricity has fallen 53% from 529 g CO2 kWh–1 in 2013 to 214 g CO2 kWh–1 in 2019 (6). The trend in emissions reduction is shown in Figure 2.

Fig. 2.

Electricity supply carbon emissions intensity. The Carbon Intensity data includes CO2 emissions related to electricity generation only. This includes emissions from all large metered power stations, interconnector imports, transmission and distribution losses and accounts for national electricity demand, embedded wind and solar generation (6)

Electricity supply carbon emissions intensity. The Carbon Intensity data includes CO2 emissions related to electricity generation only. This includes emissions from all large metered power stations, interconnector imports, transmission and distribution losses and accounts for national electricity demand, embedded wind and solar generation (6)

2.2.1 Phase Out of Coal

One of the major factors in the reduced carbon intensity of UK electricity generation is the phase out of coal. In 1990 coal provided over 60% of UK electricity generation, and while this decreased over time following increased investment in gas-fired power plants, as recently as 2012 it made up over 38% of UK electricity generation (7). UK and European Union (EU) decarbonisation policies have led to reducing profitability and the closures of coal plants since 2012, with coal making up only 5.1% of Great Britain’s electricity generation in 2018 (8).

Electricity from coal generation has been replaced through a mixture of increases in gas generation and renewable generation, primarily wind and solar. The carbon intensity of coal generation is typically over twice as high as that of gas, at 900 g CO2 kWh–1 for coal compared to 352 g CO2 kWh–1 for gas. This has meant that the switch from coal to gas has been a major contributor to the rapid fall in emissions intensity since 2012. In 2015 the UK was the first national government to announce a commitment to phase out unabated coal use, setting a target date of 2025. Great Britain has since experienced its first 24 h period of coal-free electricity in April 2017 and set a record of over a month without coal in May 2020.

2.2.2 Increase in Renewable Generation

The UK has seen significant growth in renewable electricity generation over the past 10 years. This has been supported by government renewable subsidy schemes such as the Renewables Obligation and the Feed-In Tariff, which have both now closed. Over this time the cost of wind and solar installations has dropped sharply, with the technologies entering a virtuous cycle of falling costs, increasing deployment and technological progress. Strike prices for contracts for difference (CfD) for new offshore wind projects have fallen from £114 MWh–1 in 2015 to below £40 MWh–1 in 2019 (9, 10). Global weighted average levelised cost of electricity (LCOE) of solar photovoltaic (PV) has fallen 77% between 2010 and 2018 to US$0.085 kWh–1 (11). These cost reductions have made the technologies significantly more attractive and they are beginning to compete in a subsidy free environment.

Generation capacity is the maximum power that an installation can generate. Renewable generation capacity has increased rapidly in the last decade, primarily made up of wind and solar in 2010, from 5.4 GW of wind and 0.1 GW of solar to 21.8 GW of wind and 13.1 GW of solar installed in 2018 (8). The capacity factor or load factor of a technology refers to the electricity generated by a technology as a proportion of the maximum potential generation over the period. Variable renewable technologies typically have a substantially lower load factor than fossil fuel generation due to the nature of the resources they are harnessing, for example solar PV generation is limited by hours of daylight.

Average UK load factors over the last five years range from 11% for solar PV, 27% for onshore wind and 39% for offshore wind through to 77% for plant biomass combustion (8). This means that generating an equivalent amount of energy, as currently coming from fossil fuels, would require significantly higher installed renewable capacity. The shift towards renewable energy comes with additional challenges however, particularly managing variability. This causes an issue when renewable output is low, for example on winter evenings with no wind or sun, but also when the renewable output is high, and generation exceeds demand, for example at midday in the summer when you may see coincident peak output from both wind and solar generation. Managing this variability as renewable penetration increases is a key challenge in enabling decarbonisation for the ESO.

2.3 Need for Flexibility Due to Variability and Changes in Demand

The Office of Gas and Electricity Markets (Ofgem), UK, defines flexibility as “modifying generation and/or consumption patterns in reaction to an external signal (such as a change in price) to provide a service within the energy system” (12). Demand on the electricity network varies throughout the day and across seasons. Peak demands are seen on winter weekday evenings, between 5 pm and 7 pm, with minimum demands seen historically overnight during the summer. The country needs electricity capacity to meet peak demand, which is variable, and hence the ability to increase this capacity through flexibility or to decrease the peak is pivotal.

Renewable generation always generates where it can as it has zero marginal cost. This is currently backed up by fossil fuel generation that can be turned up and down as required to help meet demand peaks. Between April and September solar generation meets a larger portion of demand during the daytime; generation is at its peak in the middle of the day when the sun is brightest. Solar generation provides relatively little contribution towards meeting evening peaks in demand, however. Wind generation output depends on the weather systems over the UK but is typically higher in winter. It is highly variable however, and the system needs to be able to manage multi-week spells with low levels of wind generation which can occur when a high-pressure system settles over the UK.

Output from large-scale transmission-connected generation is visible to the ESO and instantaneous changes in generation can be clearly seen and managed. Small-scale distribution-connected generation however, particularly embedded solar, may show up only as reduced demand on the transmission system which can make it difficult to forecast and manage.

3. How We Add Flexibility Today

The decarbonisation of the electricity system comes with several challenges from a system operation perspective. As the ESO we are responsible for balancing the system and ensuring that generation always matches demand and have a licence obligation to control system frequency at 50 Hz plus or minus 1%. If there is more demand for electricity than there is supply, frequency will fall and if there is too much supply, frequency will rise. We make sure there is sufficient generation and demand held in readiness to manage all credible circumstances that might result in frequency variations.

Fossil fuel generators are dispatchable and able to ramp production up or down, while the UK’s nuclear reactors were designed to run continuously at high load and so cannot easily ramp up and down. Generation from variable sources such as wind and solar can be curtailed where necessary to help match supply and demand but cannot be ramped upwards unless they are already at part load and spilling energy. As greater levels of variable generation come onto the system, replacing fossil fuel generators, we will need to use alternative means to maintain system stability, for example procuring services through our frequency response auctions.

The need for greater flexibility in future to enable a zero-carbon future is clear. Demand will need to become more active in response to the increasing need for flexibility on the gas and electricity systems. Currently, when output from renewable electricity generation is low, one of the primary sources of flexibility is provided by gas-fired power stations and other thermal peaking plant, this is supply side flexibility. In a net zero future, these generators will need to be fitted with carbon capture and storage (CCS) technology or retired. As such, other forms of flexibility will become more important. This includes interconnectors from Great Britain to Ireland and mainland Europe, energy storage and forms of demand side response (DSR). It could also include the use of electricity to produce hydrogen through power-to-gas or power-to-X where electricity is used to produce synthetic natural gas, synthetic liquid fuel or hydrogen. This could be operated flexibly to support the energy system, while producing dispatchable fuel for times of undersupply or for other sectors that cannot be electrified.

National Grid ESO runs a stakeholder-led programme called Power Responsive which aims to make sure there is a level playing field for both supply side and demand side solutions in Great Britain’s energy markets. Businesses which have the flexibility to increase, decrease or shift their electricity use can benefit from financial incentives to do so and help balance the network through forms of DSR. Our ambition is that, by 2025, we will have transformed the operation of the electricity system such that we can operate it safely and securely at zero carbon whenever there is sufficient renewable generation online and available to meet the total national load (13). This will require innovative systems, products and services to ensure that the network is ready to handle 100% zero carbon operation.

3.1 Current Electric Vehicle Charging Profiles

To understand the impact of EVs on the electricity system it is necessary to understand how they charge today and how this may change in future. We commissioned a Network Innovation Allowance (NIA) project to develop a comprehensive picture of current charging profiles (14). The study successfully gathered together a database of over eight million real world charge events and generated a representative full year charging demand profile at hourly resolution across a range of different location types and charger sizes. This evaluation has delivered an improved understanding of charging behaviour and enabled us to generate a more nuanced and informed view of the future impact of EV growth on electricity demand.

Existing electricity system peak demand typically occurs between 5–6 pm on weekdays, which is earlier than the peak demand for EV charging (Figure 3). This evening peak in EV demand is dominated by residential charging and is likely the result of commuters plugging into charge when they arrive home from work (it tails off as those vehicles plugged in earlier finish charging). Workplace and public charging contribute to another smaller peak mid-morning on weekdays between 9–10 am. The reduction in workplace charging rates after 10 am suggests that generally commuter vehicles plugged in to workplace chargers when they arrive are fully charged by mid-morning and remain plugged in and no longer charging subsequently until they leave.

Fig. 3.

Typical EV weekday charging profile (FES 2019) (1)

Typical EV weekday charging profile (FES 2019) (1)

Other learnings from this study include the effect of temperature on demand, where average kilowatt hour of energy per EV per day increases by 1.6% for each one degree decrease in temperature. During public holidays demand also drops, particularly over Christmas and Easter where, despite an increase in demand at (primarily motorway based) rapid chargers, this is offset by a significant decrease in other types of charging. Weekend demand is also on average 25% lower than weekdays and shows a broader demand profile shape that peaks an hour earlier.

It is clear from the data that current charging patterns will contribute to increased peak loads on the electricity network at both distribution and transmission levels. This may present more of a problem for the distribution network where the existing peak demand is often later than on the transmission network. If charging patterns can be shifted to increase levels of overnight and daytime charging at the expense of evening charging this could have a beneficial network effect and help reduce carbon emissions, as peak demands are more likely to be met by dirtier fossil fuel generation peaking plants.

This study has captured the charging demand of plug-in cars, but as other vehicle segments electrify demand will change. This, for example, includes depot-based vans, taxis and buses that may show different demand profile characteristics and present different opportunities.

3.2 Future Energy Scenarios Range of Outcomes

As part of FES 2019 we developed four scenarios setting out a credible range for how energy demand and generation could develop out to 2050 (Figure 4). This includes projections of the levels of renewable generation, EV take-up and flexibility.

Fig. 4.

Scenario framework for National Grid ESO’s FES 2019 (1)

Scenario framework for National Grid ESO’s FES 2019 (1)

Two of our scenarios met the national decarbonisation target at the time of an 80% reduction in 1990 emissions by 2050. These are Two Degrees, which relies primarily on centralised generation and Community Renewables which has a greater proportion of decentralised generation. The UK government has since tightened the 2050 target to net zero CO2 emissions. It is likely that new policy and support will be put in place to achieve this aim, therefore we would expect that by 2030 the electricity system would be closer to Two Degrees and Community Renewables than the other two scenarios which did not meet the 80% reduction target. Net zero in 2050 was modelled as a sensitivity in FES 2019 and will be included in core scenarios in FES 2020.

Figure 5 shows the installed electricity generation capacity of different technologies in 2018 and the projected changes to this under the different scenarios in 2030 and 2050. In all scenarios overall capacity grows, but this is particularly noticeable in the faster decarbonising scenarios, Two Degrees and Community Renewables. These two scenarios have a higher proportion of renewable generation and much of this capacity is variable, with a low load factor, meaning more generation capacity is required to meet overall energy requirements at times of high demand, particularly in winter. The total installed capacity significantly exceeds forecast peak demands to account for this. Due to their lower load factor and variability, renewables are de-rated when calculating the capacity required to keep the lights on as they will not always be available to contribute at peak times (15).

Fig. 5.

FES 2019 installed electricity generation capacity (1)

FES 2019 installed electricity generation capacity (1)

Figure 5 also shows potential future avenues to add flexibility, with significant increases in interconnector capacity and storage capacity, particularly across the more decarbonised scenarios. Interconnectors will allow the UK to trade more electricity with mainland Europe at times of high demand or excess generation. Shorter duration storage projects could meet small periods of increased demand or provide flexibility services such as frequency response. Longer duration storage is well suited to covering longer periods of, for example, high or low wind, potentially co‐located with generation. Some of the other key outputs from FES 2019 are set out in Table II for 2030.

Table II

Future Energy Scenarios 2019 Assumptions to 2030 (1)

Technology Change from now to 2030 Uncertainty factors
EVs Large increase from 150,000 today to between 2.3 million and 12 million Large range to reflect uncertainty, but technology and policy direction suggests high end of range
Interconnectors Large increase from 4 GW today to between 12 GW and 20 GW Large range reflecting project risk, but minimum backed by Ofgem’s cap and floor regime and projects under construction
Transmission-connected gas generation Scenarios range from no change to a large decrease. Economic pressure suggests a reduction is most likely as other sources of supply, such as wind and interconnectors, take market share
From 31.1 GW today to between 9.7 GW and 33.3 GW
Offshore wind Large increase from 8.5 GW today to between 20.9 GW and 33.6 GW High growth expected due to sector deal of 30 GW by 2030 and falling costs as seen in the September 2019 CfD results of < £40 MWh–1. Costs have fallen significantly from £120 MWh–1 for round one projects
Distributed generation – installed capacity Large increase from 30.9 GW today to between 38 GW and 70.3 GW Charging reviews likely to reduce growth in the shorter term, but growth is still expected in the longer-term due to falling costs of distribution-connected solar, onshore wind and gas peaking plant displacing transmission-connected combined cycle gas turbine (CCGT)
Distributed generation – contribution to peak demand Large increase from 9.4 GW today to between 12.9 GW and 26.2 GW Charging Reviews likely to have an impact in the shorter term, but growth likely due to falling costs of distribution-connected solar, battery storage, onshore wind and gas peaking plant displacing transmission-connected CCGT
Electricity storage Large increase from 4 GW today to between 7 GW and 13 GW Increasing levels of variability from renewables, tightening environmental restrictions on gas peaking plant and falling costs of storage expected to strengthen storage business cases
Carbon intensity of electricity Large decrease from 248 g CO2 kWh–1 to between 112.7 g CO2 kWh–1 and 24.9 g CO2 kWh–1 High uncertainty dependent on delivery of low carbon supply above

3.3 Oversupply of Electricity

In the faster decarbonising scenarios of Two Degrees and Community Renewables, the growth of low-carbon capacity will contribute to periods of oversupply of electricity, particularly in the summer months beyond 2030. Inflexible renewable generation capacity will at times produce more electricity than total demand. The annual amount of excess electricity rises to 20–25 TWh (around 6% of total annual output) after 2040 in Community Renewables. Our modelling shows that at times of likely oversupply, excess electricity cannot be exported, as other countries that have decarbonised are likely to be facing similar issues. Nor can it be stored, as available storage is full.

Future markets will determine how this electricity could be used, stored or curtailed in the most efficient way; this could include use of electricity to produce hydrogen or charge EVs. This is likely to be attractive to consumers as power prices will be very low or negative at times of oversupply meaning consumers could be paid to use the electricity when carbon emissions are also likely to be low.

National Grid ESO has developed a Carbon Intensity forecasting tool (Figure 6) (6) in partnership with Environmental Defense Fund Europe, UK, University of Oxford Department of Computer Science, UK, and the World Wide Fund for Nature (WWF), Switzerland. It uses machine learning and power system modelling along with Met Office, UK, data to forecast the carbon intensity and generation mix 48 h ahead for each region in Great Britain. The forecast carbon intensity figures are accessible via a website, the National Grid ESO app and an application programming interface (API) to allow developers to produce applications that will enable consumers and smart devices to optimise their behaviour to minimise carbon emissions. WWF have implemented the API into a widget that can help people plan their energy use, switching devices on when energy is green and off when it is not.

Fig. 6.

Carbon Intensity tool output showing 24 h of historic data and a 48 h forecast from 30th October 2019 (6)

Carbon Intensity tool output showing 24 h of historic data and a 48 h forecast from 30th October 2019 (6)

3.4 Smart Charging and Vehicle-to-Grid

The data from our EV innovation project suggests that EVs typically spend long periods of time plugged into residential or workplace charge points and current charging patterns result in vehicles starting to charge as soon as they are connected to the charger with little to no smart management of charging. Smart charging enables consumers to manage the time when their vehicle is charged. This could be to take advantage of lower prices or lower carbon electricity or to respond to external signals from third parties such as aggregators or network companies.

The government’s Automated and Electric Vehicles Act 2018 (16) sets out requirements for all new charge points sold or installed to be ‘smart’. This means they must be able to receive, process and react to information or signals, such as by adjusting the rate of charge or discharge; transmit, monitor and record information such as energy consumption data; comply with requirements around security; and be accessed remotely. This legislation aims to avoid infrastructure being a blocker to future smart charging developments.

EV batteries can be considered as a form of storage within the wider energy system, though the impact of EVs is fundamentally different to other forms of storage. This is because not all vehicles are connected to the system at any point in time, meaning that the available storage capacity from EVs is constantly varying. This creates natural diversity in availability and charging behaviour for EV batteries and means that the potential for EVs to increase, shift or decrease demand varies and is a fraction of the total capacity of EV batteries in Great Britain at any one time. BEV batteries are typically five to 10 times larger than PHEV batteries, so the relative mix of PHEVs to BEVs will also affect the total energy capacity available.

Consumers can be incentivised to take part in smart charging and delay the start of their charging period through time-of-use (ToU) tariffs and be guided by tools such as National Grid ESO’s Carbon Intensity app; these are already available to consumers to allow them to schedule their EV charging for times of lower prices or carbon emissions. A more dynamic form of smart charging involves in-home automation and smart management and optimisation of charging while the vehicle is plugged in without active involvement from the consumer. This would remove barriers for consumers to get involved and have a significant impact on the electricity system and resulting carbon emissions. This will become more important as the number of EVs on the system grows. These ToU tariffs are already available for consumers from some innovative energy suppliers such as Octopus Energy, UK, and are expected to become more widely available over time.

An additional avenue for EV to have a positive impact on the electricity network is through the use of V2G technology. This is where electricity stored in the battery of an EV can be supplied back into the network through a two-way V2G enabled charger. This process is likely to be managed by an aggregator triggering response from a large portfolio of vehicles contracted to deliver this capability, they would likely offer financial incentives to consumers to facilitate this. Individuals and businesses could also use this to take advantage of variable rate tariffs without the third-party involvement. There are a range of pilot projects developing this technology; in 2017 the UK’s innovation agency, Innovate UK, committed £25 million in support to eight real world V2G demonstrator projects undertaken by a range of organisations including energy suppliers, network operators and small and medium-sized enterprises (SMEs) (17).

Battery lifetimes are typically measured in the number of discharge cycles they can undergo without battery capacity falling below a certain threshold. The measurable impact of V2G on battery health is still at the research stage, with recent papers providing seemingly contradictory conclusions. Dubarry et al., 2017 (18) showed that additional battery cycling due to V2G would shorten battery life; while Uddin et al., 2017 (19) indicated that battery degradation could be avoided. These authors have since published a joint study in which they “jointly reconcile their previous conclusions by providing clarity on how methodologies to manage battery degradation can reliably extend battery life” (20). It is clear, however, that further research in this area is necessary to determine the effects of V2G and ensure it is an attractive proposition for both electricity networks and consumers.

Our FES 2019 scenarios consider how engaged vehicle owners are likely to be with smart technology and V2G and build these assumptions into our modelling of peak demand. We classify a consumer as participating in smart charging if they actively choose not to charge their EVs at peak times, wherever possible. We assume that only 2% of vehicle owners engage in V2G through to 2030 as the technology is still at an early stage, however that number then steadily increases to 2050, with the highest levels in the Community Renewables scenario. These participation rates are shown in Table III.

Table III

Smart Charging and Vehicle to Grid Participation Rates in 2050

Smart charging participation, % V2G participation, %
Community Renewables 78 14
Two Degrees 65 11
Consumer Evolution 73 13
Steady Progression 61 10

3.4.1 Impact on Peak Demand

Figure 7 shows a typical weekly residential EV charging profile. This shows the peaks in weekday demand as consumers plug in after work and the troughs overnight which occur once consumers have finished charging. The average load per vehicle is around 0.4 kW per EV, this suggests that only a proportion of total EVs are plugged into charge, with typical domestic charge rates varying between 3 kW and 7 kW. At weekends the demand profile is spread more broadly throughout the day with a far smaller evening peak. Average energy delivered to vehicles each day varies between 2.5 kWh and 5 kWh per day across the year, indicating average daily miles driven are below 25 miles per day. This level of energy demand could be met through software to automatically stagger charging times to start later, reducing peak load significantly for the 61–78% assumed to participate in smart charging.

Fig. 7.

Weekly demand profile, averaged over full year, for residential charging for an average EV (15)

Weekly demand profile, averaged over full year, for residential charging for an average EV (15)

Adding V2G technology would enable a further reduction in peak demand as some EVs plugged in at peak times would be able to feed energy back into the grid to offset existing peak demands. Cars that are also charged at their workplace during the day would also have more energy in their battery when plugging in at home and therefore be better able to participate in V2G.

Figure 8 shows the potential impact on peak demands with and without smart charging and V2G in the Community Renewables scenario. This scenario has rapid uptake of EVs, with 11.5 million EVs by 2030 and 31.3 million EVs by 2050. This compares to the slower rate of EV take-up in Steady Progression where there are only 2.2 million EVs in 2030, rising to 33.6 million EVs in 2050. The high number of EVs owned by highly engaged consumers demonstrate significant impacts on peak demand, with unconstrained charging potentially resulting in 24 GW of additional peak electricity demand in 2050 compared to only 12 GW if smart charging is undertaken by engaged consumers or less than 2 GW of additional peak load if some vehicles are participating in V2G.

Fig. 8.

FES 2019 Community Renewables EV charging behaviour at system peak (1)

FES 2019 Community Renewables EV charging behaviour at system peak (1)

This behaviour is valuable as it reduces future peak load growth substantially, avoiding potentially costly electricity network reinforcements. The potential reduction in peak load of 22 GW is equivalent to nearly seven Hinkley Point C reactors (the 3.2 GW nuclear power station currently under construction in Somerset). This represents a potential large cost saving compared to the unconstrained charging case and indicates that smart charging and V2G can provide significant value to the electricity system.

3.4.2 Impact on Oversupply of Renewable Generation

As highlighted in Section 3.3, as installed levels of renewable generation increase there will be an increase in times when generation exceeds demand and excess renewable generation must be curtailed. We have carried out further analysis of the potential for EVs to support the energy system through smart charging to absorb some of this excess generation. The FES 2019 demand and generation dispatch projections were assessed for 2030 using the Community Renewables scenario. EV charging profiles for residential and workplace charging were load shifted away from peak times, with a 47% reduction in peak demand (1) shifted to charge overnight between midnight and 6 am, unless there was oversupply at peak. This resulted in a 7.3% reduction in renewable generation curtailment in 2030. Figure 9 shows an example week in January where curtailment is reduced by EV load shifting.

Fig. 9.

Example week in January 2030 showing the potential for EV charging load shifting to reduce curtailment of renewable generation at times of oversupply. Generation output is modelled in 4 h blocks, so generation variability may result in lower utilisation of oversupply unless this is smoothed out by short-duration storage

Example week in January 2030 showing the potential for EV charging load shifting to reduce curtailment of renewable generation at times of oversupply. Generation output is modelled in 4 h blocks, so generation variability may result in lower utilisation of oversupply unless this is smoothed out by short-duration storage

The potential reduction in curtailment due to EV smart charging is likely to increase post-2030 as renewable generation capacity increases, and these periods of oversupply become more frequent and EV charging peaks grow; the number of EVs in Community Renewables is forecast to increase from nearly 12 million in 2030 to over 30 million in 2050.

4. Conclusion

EVs can help decarbonise both transport and electricity supply for Great Britain. This is both via reduced tailpipe emissions and due to the flexibility that EV batteries can offer to the electricity system. They offer a source of untapped flexibility that can provide significant benefits to Great Britain’s energy system.

The challenge of meeting a net zero carbon emissions target for the UK is substantial and will require transformation across the economy. Within the energy sector the growth in renewable generation and decline in traditional dispatchable generation such as coal and gas plants represents a significant change. This may lead to times of oversupply of renewable generation at times of low demand and challenges in meeting peak demands when renewable generation output is low as the power sector decarbonises. There will therefore be greater need for flexibility services that can help manage the variability of generation on the system.

Beyond this, demand is also likely to change as the transport sector is electrified. This has the potential to add significant additional load to the electricity network as consumers switch to EVs to replace petrol and diesel vehicles. If all consumers charge at times of existing peak demand this will require significant and costly reinforcement of the electricity networks to facilitate this. However, the use of smart charging and V2G technology means EVs can instead provide flexibility and help to integrate a higher level of renewable generation on the network through load shifting to times of oversupply. This amplifies the positive impact of EVs on decarbonisation.

As higher capacities of renewable generation are required to meet the same annual demand as thermal generation like gas or coal, if wind and solar output is high at periods of low demand there is a risk of oversupply. ESO modelling shows that excess electricity could rise to around 6% of total annual output after 2040. This power cannot be exported, as other countries that have decarbonised are likely to be facing similar issues, and it cannot be stored as available storage will already be full.

FES 2019 modelling suggests that EVs being charged with smart technology or responding to V2G could reduce additional network peak demand from EVs by over 90% in 2050 in our Community Renewables scenario. They could also enable the storage of roughly one fifth of Great Britain’s solar generation for when this energy is needed. In 2030, smart charging to shift demand from evening peaks to times of renewable oversupply could result in a 7.3% reduction in renewable generation curtailment, this could increase further by 2050.

National Grid ESO are well placed to understand these potential changes through our management of the electricity system and our annual FES publication. Our ambition is that, by 2025, we will have transformed the operation of the electricity system such that we can operate it safely and securely at zero carbon whenever there is sufficient renewable generation online and available to meet the total national load.



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Some material has been republished from National Grid ESO’s 2019 FES with permission. Thanks to National Grid ESO colleagues Alex Haffner, Lauren Moody, Marcus Stewart, Dave Wagstaff, Ricky Moseley and Juliette Richards.

The Author

Archie Corliss is Strategic Insight Lead at National Grid ESO, producing content for the FES and winter and summer outlook publications. He has a background in energy consultancy and assessment of integration of renewable generation, energy storage and EVs within constrained areas of electricity networks.

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