uk - norway plugin vehicle roundtable summary report

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UK-Norwegian Plugin Vehicle Power Grid Roundtable Summary Report June 21-22nd, 2017 Held at The Research Council of Norway, Oslo, Norway

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Page 1: UK - Norway plugin vehicle roundtable summary report

UK-Norwegian Plugin Vehicle

Power Grid Roundtable

Summary Report

June 21-22nd, 2017

Held at The Research Council of Norway, Oslo, Norway

Page 2: UK - Norway plugin vehicle roundtable summary report

Background

The electrification of transportation will play a critical role for the UK’s ambitions to meet its

legally binding 2008 Climate Change Act targets of 80% reduction in GHG emissions by 2050.

This transition to the electrification of personal transportation has commenced and is steadily

securing its foothold of success, as an increasing number of countries move forward on their

trajectory of plugin vehicle uptake in effort to support policy goals on CO2 reduction and/or air

quality improvement. While still at the early stages of this development, countries around the

world are likely to confront issues of grid in the near future, ranging from local distribution

constraints due to ownership or charging point clustering in the near term, to broader

constraints such as generation capacity in the long term. Strengthening the relationship

between the automotive sector and the power grid will become be key to realise the potentials

of transport electrification.

The Roundtable

International knowledge sharing, technology transfer and partnerships can help reduce

investment risk and system costs, as well as help enable a seamless development of the EV

market in the UK. As such, the Research Council of Norway hosted UK-Norwegian Plugin

Vehicle Power Grid Roundtable – jointly organised by Innovate UK, the UK Science &

Innovation Network and Enova on June 21-22nd 2016 in the Norwegian Capital of Oslo.

This report

This informal report is an digest of the observations made by participants at the round table,

based on information and perspectives at the time of the event.

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Participants

UK participants Norwegian participants

Jim Cardw ell Northern Pow ergrid Birger Bergesen

David

MacLeman

Scottish and Southern

Electricity Netw orks

Christer Skotland

Martin Queen Ofgem Johan Christian Hovland Hafslund (energy supplier)

Adrian Vinsome Cenex Joakim Sveli

Thomas

Maidonis

National Grid SO Tina Skagen

Nick Brookes Office for Low Emission

Vehicles

Jonas Helmikstøl ZapTec (smart charger)

Sally Fenton BEIS innovation delivery team Ole Henrik Hannisdahl Grøn Kontakt (charger

operator)

Liam Lidstone ETI & Energy Systems Catapult Jan Haugen Ihle Fortum - Charge & Drive

Dan

Hollingsw orth

EA Technology Øystein Ihler Municipality of Oslo

Tobi Babalola UK Pow er Netw orks Andreas Bratland

Rosie McGlyn Energy UK Erland Eggen

James Court Renew able Energy Association

Patrick Agese Reading University

Mark Thompson Innovate UK

Mikael Allan

Mikaelsson

UK Science & Innovation

Netw ork

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The Electrification of Transportation in the Context of Norwegian Energy &

Climate Policy

The city of Oslo has set out clear climate targets of 50% CO2 reduction by 2020 and 95%

reduction by 2030 as part of its Zero Emission City Strategy. The strategy is build on three key

pillars around i) mobility, ii) energy and iii) city governance, and consists of 76 actions points

over the next four years up to 2020. While Norway boasts an electricity system that is 100%

renewables from hydropower, the city of Oslo is currently on a journey to reduce CO2 emission

from transportation which currently makes up 61% of Oslo’s total carbon emissions. A recent

assessment of the distribution of carbon emissions from transportation demonstrated 15% of

CO2 emission coming from heavy duties vehicles (i.e. transportation of goods) with additional

10% from light freight. While the bulk of emissions came from personal transportation, or 39%,

surprisingly high carbon emissions of 30% were identified coming from construction

machineries. As such, Oslo is making inroads on the electrification of construction machineries

as well, as it’s establishing itself as a European test-bed in this area and is currently running

six pilot projects.

As part of its strategy, the city of Oslo is focusing on optimising the transportation system and

mobility and aims to reduce traffic by 20% by 2020 and 33% by 2030. According to the city’s

climate strategy, all new cars in Oslo will have to be fossil-fuel free by 2020 and there are

being established automotive vehicle-free city centre and low emission zones. The city will

promote the sharing of open specification data for smart city mobility. Toll stations have been

installed to fund the metro system and charging station, with differential toll pricing to

encourage less polluting vehicles. Oslo is working very closely with Copenhagen, Malmö and

Hamburg on a major project (GREAT –Green REgions with Alternative Fuels for Transport)

focusing on heavy trucks (national and international transport) and truck for c ity logistics,

where these cities are delivering infrastructure (i.e. energy stations) for alternative fuels in the

highway systems, including zero emissions vehicles (e.g. EVs and H2) and renewable energy

(e.g. biogas and biofuels). Oslo is also currently electrifying its public bus fleet. The city of

Oslo approaches the electrification of transport from whole systems perspective with a strong

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emphasis on the local micro system to optimise energy use. The challenges in Norway

regarding the electrification of transportation are largely regulatory and pragmatic in nature

rather technical. The city of Oslo’s is also largely focusing on micro energy systems that will

enable the optimisation of energy use locally and in the main grids. The main grid’s connection

to the micro energy systems will allow greater energy exchange between energy vectors, and

to receive and deliver energy locally to and from the main energy grids – both in terms of water

based (i.e. for heating and cooling) and electric based systems. This work will strengthen the

connectivity between energy and buildings on one hand, and energy and transportation on the

other hand.

Fortum Charge & Drive is currently the utility in the world with the highest share of EVs’

penetration amongst its customers (46,000 EVs in total) and therefore have a good insight of

the every-day life of EV customers. Norway has a 95% hydropower-based electricity system

(at 130TWh per annum), which coupled with a strong grid, is capable of catering to the

increasing EV deployment that has led to an increasing electricity demand over the last 10-20

years (0.5TWh per annum, at present). Nevertheless, there will still be a need to invest in

additional capacity, particularly at local levels where the grid is relatively weak. The investment

in EV infrastructure initially began with the city of Oslo establishing charging stations in the

city centre but the investment is now shifting into establishing charging stations in private

homes and condominiums. Earlier, some condominium management companies were initially

against the installation of EV charging but this has progressively changed and charge point

installation has now become driven by market demand since apartments currently without EV

charging would demand significantly higher price less than apartments with EV charging. This

in turn has driven the need to upgrade infrastructure and at present approximately 80% of

condominiums in Oslo have charging infrastructure.

The Electrification of Transportation in Context of UK Energy & Climate Policy

The UK energy market which consists of over 50 different energy suppliers and separately

regulated distribution network operators and system operators, is largely driven by competition

at the energy retail level. In the UK there are binding climate commitments and carbon budgets

which set obligations for the UK Government to move forward on the decarbonisation agenda

up to 2050. Furthermore, much of the recent decarbonisation taking place in the UK is

occurring in the power sector where most coal power stations are expected to come off line

by 2025. Today however, the decarbonisation of the transport sector has made centre stage

and is currently in motion, but although of the greatest challenges for the UK climate targets

lie around the decarbonisation of the heating sector. Unfortunately, approximately 80% of UK

households are using gas boilers and there is no effective roadmap available to drive forward

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the decarbonisation of heating in the UK. The lack of CCS is also a major gap in the UK low

carbon policy ecosystem following the shut down of the major CCS competition by the last

Government administration in 2016. In contrast, the electrification of transportation is likely to

move forward successfully at pace as this area as it lends itself to cross-party support. From

an UK energy retailer/generator perspective, EVs will play a key role for of the decarbonisation

of the energy system. Moreover, it will be critical that the policy and technical architecture for

EVs and smart charging will enable a framework that puts the customer in control and enable

them to extract real value from the EV asset in context of V2G (particularly since EVs are

currently more expensive that ICE vehicles), as well as time of use-tariffs to help move the

charging load to later in the evening. There also need for greater opportunities to be provided

from EVs on a local community level to enable a local energy system. Another difficult

challenge is to identify where tax revenues will come from a transportation system defined by

EVs.

The electrification of transportation is taking place in a context of transportation culture that is

already in flux. The number of private vehicles in the UK is at an histor ical height with

approximately one vehicle per household although mileage usage has reduced by 1500km/per

year over the last ten years. The ownership of vehicles has changed over the years with 80%

of all new cars (90% for EVs) are purchased via lease deals (averaging at €250 per month),

whereas only ten years ago this share of only 30%. The younger demography is increasingly

moving into urban environments with decreasing interest in owning a car. The UK

Government’s approach towards the electrification of transportation consists of four focal

points, which are: I) inward investment in EV in the UK, ii) carbon impact (transport makes up

25% of carbon emissions), iii) air, and iv) energy security. The UK Government’s pledge of

“almost every car/van to be zero emission by 2050) is being backed up by the Treasury with

£600million investment from 2015-2020, together with an additional £500million for advanced

propulsion centre and £100million in tax incentives. Furthermore, last autumn the UK

committed further £250 million to invest in infrastructure development. The Office for Low-

Emission Vehicles (OLEV) runs five different schemes to push forward EV. Two of those are

grant schemes focus on encouraging the establishment of charging infrastructure for EVs at

homes and workplaces. Another scheme aims to incentivise local councils to put in place

charging infrastructures. There is a plugin car grant that partly subsidises the purchase of EVs.

OLEV also runs a communication strategy called Go-Ultra Low to promote the EV deployment

in the UK. OLEV’s strategy paper set out targets to meet 1.5% share of EV of all new cars.

However, while the UK is currently on track, the trajectory will increase exponentially over the

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next few years. At present, there are around 12.000 charging points across 3000 locations in

the UK (97% of motorway service stations have rapid charge points).

The DNOs in the UK have placed a strong focus on the commercial customers who are likely

to be more significant and pressing in terms of needs. For example, Europe’s largest EV bus

fleet has come into effect at the Waterloo Garage in London that uses 43 electric buses that

are all being charged at 40-80kW, needing 2.5MWA connection to achieve this. Furthermore,

there are plans to electrify the entire London bus fleet in the next few years, which counts

approximately 70 garages with around 100 EV buses per garage.. In terms of the smart energy

system required to enable the lift-off of the electrification of the transportation system, some

DNOs anticipate that the key issues will revolve around the software needs rather than issues

around hardware, standardisations or policies. In this context, the utility sector needs to

prepare itself for a world where smart IT platforms will provide regionally-specified demand

and require the DNOs to send the appropriate signals, but many utilities do not boast this

capability at present. However, in the UK there are concerns of how to ensure that the charging

infrastructure will be smart to allow remote management and access to the flexibility market

since it will be difficult for customers to select smart charging over to a future standard if they

have to cover the additional cost.

Grid Impact and Pinch Points

It is of paramount importance to consider the impact of EVs on the Norwegian grid as the

country is projected to have 1.5million EVs by 2030 (50% of all personal vehicles). Certainly

the effect of EV penetration on the local network load will be proportionally smaller relative to

the UK since electricity is also the primary source of heating in Norway. Nevertheless, in the

last 10-15 years there have been significant efforts to strengthen and reinforce the grid to allow

sufficient capacity for the electrification of the entire vehicle fleet as anticipated. While there is

sentiment among some Norwegian stakeholders that the need for capacity is being

exaggerated and that this challenge can easily be dealt with by using 3 phase to avoid load

issues for the individual household as well as the neighbouring households, a recent study by

NVE indicated that a number of transformers could be at risk of overload. According to the

findings, there would be approximately 1% of transformers would overload under conditions

of an additional 1kW per household, 8-9% of transformers under conditions of 2kW increase

per household, and 30% of transformers under conditions of additional 5kW per household,

but a scenario of 1-2kW increase per household is considered the most likely with EVs on the

system. The average load on a cold winters’ day in Oslo is approximately 4.5kW but the future

deployment of controlled charging regime via smart metering should enable EV charging to

take place without increasing the maximum power consumption of an average household.

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In Norway, there has also been an increasing recognition that it is important to differentiate

between challenges for the individual household customer and the grid when it comes to

capacity for EV charging as many customers assume they will need greater capacity than they

actually do. Therefore, it is important to get in place the right charging infrastructure to enable

automated charging that ensures the right charging pattern since most customers will not need

that much charging capacity on a daily basis. While some customers do request for a 22kW

home chargers, they do not need it in practice, fact that is made clear to them by the local

network operator. If they do insist on charging capacity of this size they are charged for the

network upgrade cost. If the household is using the largest EV on the market today, a 6kW

chargers would enable full charging from 6pm to midnight for most users (nobody drives

400km per day every day of the week). As such, 3kW chargers would suffice for the average

customers (usually with a 20A fuse installed – although with recommendations to use only

16A) with perhaps 6kW made available for long-distance/frequent drivers. Since EVs don’t

require that much capacity for smart charging and therefore instead of installing 150x 20A per

building it would be more sensible to install say 63A divided across all users, which will result

in a lower return, lesser need to invest in the external grid system or induce cost to the grid

that others will have to pay. However, one argument for a greater capacity (or at least cabling

that enables greater capacity to the charger) in individual chargers is that it would provide

greater flexibility – particularly in office and apartment buildings. This flexibility in the system

would offer the possibility to deliver demand side response efficiently and load manage against

the building (or for V2G), and therefore has real value. In Norway, it is commonly

recommended to adopt a 3 phase system rather than 1 phase if there is interest in investing

in greater capacity, although the key question remains who should be paying for the greater

capacity installed in the infrastructure. Norwegian distribution network operators (DNOs) are

quite progressive in experimenting with various “behind -the-metre” solutions to avoid

connection costs, which will have important benefits for customers with power -sharing

management systems such as in shared residential car parks in multi-storey serving

apartments blocks. In addition, Norwegian DNOs are quite confident that the upcoming EV

penetration can be accommodated due to both high capacity and strong infrastructure with 3

phase supplies.

Managing Grid Load and Charging Behaviour: A Need for a Price Signal or

Managed Charging?

The DNO/DSO for Oslo and surrounding region currently operates a smart grid supplying and

managing electricity to 700,000 customers with a facility on their web site so homeowners can

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see their home has power connection headroom for EV charging. They are rolling out smart

meters currently with the capability of sampling meter throughput at 2 minute intervals to help

manage the network in the future more effectively (UK smart meters in comparison report data

at a 30-min granularity). Recently however, some Norwegian smart charge solution providers

that are installing load management system for AC charging have become concerned that

the most customer friendly load management programme for an AC setup will max out the

main fuse due to the absence of a pricing signal. In the effort to balance EV charging against

the building, the usage of whatever capacity remains under the main fuse for EV charging that

would be beneficial for the customer, would create a disastrous situation for the service

provider. Therefore, there is a growing consensus around the importance of time-of-use tariffs

(ToU) in order to influence people’s charging behaviour and discourages people to engage in

the homogenous charging behaviour that would lead to a reduced peak demand between 5-

10pm. While much of the needed technology setup to receive, process and act on this signal

already exist, the market place for smart charging service providers to obtain a pricing signal

does not exist since there is no spot-price for kWh. A market place that allows price signalling

would enable the curbing of power charging and create the needed flexibility on a DSO level.

While the Norwegian Government has some plans to introduce ToU tariffs within the next

couple of years, these plans fall somewhat short of the demands from charge point operators

who argue for a more sophisticated local energy/flexibility markets. This type of market

mechanisms is by many considered essential so that business development and models can

be designed to enable and incentivise peak shifting in charging behaviour to the less

demanding periods during working hours or overnight.

While there is a growing consensus on the importance of ToU tariffs in order to influence

peoples’ charging behaviour, some challenges could arise from the fact that two different price

signals may emerge and diverge: there is the pricing signal from the wholesale spot -market

(i.e. the MWh needed by the suppliers) and there is the price signal from the impact on the

local DNO/DSO network. For instance, a government might react homogenously to a spot-

market signal which could have a significant impact on local networks. At the same time, there

is no visibility of where the loads of the aggregating controls are at any given moment from

the DNO to the TSO and therefore DNOs have no visibility of the impact on the distribution

network when the TSO is balancing frequency and sends out a signal. Therefore, it will be

crucial to find a solution to balance these two different signals (although a flexibility market

could go some distance in addressing this predicament). However, there are a number of

projects where DNOs and TSOs are working together to address this issue and to gain better

understanding how actions on one system impacts the other system, via data exchange and

use of software platforms to provide visibility (albeit no control).

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Furthermore, there are some concerns that the construction of a pricing structure based on

today’s load could become troublesome if it indeed successful ly changes user-behaviour as it

risks creating new congestion scenarios in the low-tariff timeframe. In addition, it would be

problematic or perhaps impossible to constantly change the ToU tariff. In this kind of swing

scenario, it might be required to change the time-of-use tariffs to every other year. At present,

Norway is moving towards the adoption of charging tariffs that will be based on peak demand

rather than customer use. As the transition moves forward, another issue that needs to be

considered is whether there is a need for a differential electricity system for EV charging and

other household electricity use, or whether the two will be linked to the same demand profile

and tariffs. Fortum has also launched a comprehensive education programme to in form

customer case handlers and customers how to participate in the EV transition and to optimise

their EV assets. For example, Fortum is operating a website where individual household can

learn about the electricity capacity of its own building based on the cut-out rating.

According to other industry actors however, these concerns about peak demand may perhaps

be somewhat inflated. Some argue that the Norwegian population is diversified enough in

terms of characteristics and behavioural patterns. For instance, while Norway’s total

population counts 5.1million only 2.6million are working, and of which only 1.7million have

regular working hours. Further, out of the 1.7million who have normal working hours, only 1

million use cars to get to work. This means that perhaps only 1 in 3 cars will be charging at

the close of the average working day at 5pm. In addition, the increasing number of charging

stations at the workplace is considered likely to mitigate this problem even further and in larger

cities (e.g. London) it unlikely that peak charging will coincide with peak electricity demand

due the limited availability of domestic/residential car parking and thus greater reliance on

charging points in public car parks, supermarkets and workplaces. It also remains to be clear

whether customers would actually act rationally to a price signal as some work suggests that

comfort may override cost-savings as a determining factor for peoples’ charging behaviour.

The greatest challenge around the electrification of transportation from the UK DNO

perspective is identify ways to alleviate the pressure on the low voltage network. While there

are a number of options around the table around market mechanisms, pricing signals, market

creations, and influencing customer behaviour, it is difficult for DNOs to have confidence these

solutions when there is a requirement for 100% reliability all of the time to prevent burning

cables out on the street. Therefore, it is difficult for DNOs at present to envisage a market

mechanism, a price signalling and customer behavioural result that will provide this kind of

certainty, which leaves a technical solution as the only option on the table as it is more reliable

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and better manages risk. Therefore, the most attractive option to avoid the potential challenge

around coinciding peak demands (i.e. across EV and other domestic electricity use) is to adopt

a managed charging regime where customers will not be actively responsible for the “smart”

charging schedule. From the perspective of the DNO’s, this kind a technical intervention might

be more reliable and better manages risk, as it would remove the decision away from the

customers by using some smart IT system (e.g. e-Smart Systems) to avoid new peaks.

Essentially, the DNOs require a facility that can be called upon to reduce the charging rate for

EV at times when there is a problem in balancing supply and demand. However, the question

is whether it is possible to forecast when such problems will occur through customer profiling,

data mining, smart technology etc., or will it only be possible to learn about it when something

happens. The UK DNOs currently have a very limited visibility of the distribution network and

therefore need smart charging. However, there are a number of barriers to adoption. Firstly,

customers can install EV chargers without a “new” connection agreement. Secondly, while

smart charging represents the most cost-effective solution for customers in the longer term,

there is no minimum standard for eV chargers to be capable of managed charging nor a

commercial or regulatory mechanism to implement managed charging. Finally, because

existing chargers are not upgradeable to “smart”, early action is imperative to ensure

technology is available at time of need, since delays in addressing this issue will require

greater intervention that will be costly and perhaps against public acceptance.

In order to enable the smart charging capability and remove these barriers, a wide range of

stakeholders (automotive, energy supply, transmission, government, charge point

manufacturers and customer groups) need to be consulted to work towards a technology

standard/specification and to raise the awareness of the wider benefits provided by sma rt

charging, such as lower energy bills (via ToU tariffs) and enable participation in flexibility

markets that will provide revenue streams for customers. Furthermore, a regulated

commercial flexibility market platform is required to load balance and maximise opportunities

from smart charging and distributed energy resource (DER) optimisation.

Maximising EVs and other DER Assets by Approaching Energy as a Service?

Only few years ago, the idea of installing solar PVs in Norway was considered outlandish in

context of the country’s weather climate and the amount of relatively cheap hydropower it had

in its system. However, in recent years a Norwegian companies such as Otovo may be

disrupting the country’s electricity market. Otovo utilises a software platform where

households can register their home address, and via the use of satellite and smart algorithms,

the company provides the registered household with a comprehensive summary on the solar

PV potential and optimisation (e.g. the amount of solar energy ava ilable, optimal angles for

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maximum PV performance, ideal location, size of installation etc.) for that household. This

option has allowed households to save around NOK273(£27)/per month at the same time as

the grid operators, electricity generators and state lose approximately three-fold that amount

due to the reduced electricity demand from the “prosumption”. This has raised serious

concerns among grid operators who risk seeing a decline in their revenues for grid cost as

they rely on £1.1billion via households’ electricity bills (i.e. £500 per annum for household,

accounting for a third of the bill, with state VAT and electricity cost account for the remaining

two thirds). Since it would not play well to let industrial customers take on the additional cost

to compensate or to defer grid upgrades, the grid operators would be forced to establish a

new tariff to recoup the loss. However, this would make it even more economically attractive

for households to disconnect from the grid as there could be up to £770 premium per year,

although a major challenge remains around very low PV-production and high energy demand

during winter with seasonal darkness and cloud coverage, making it very difficult to go

completely off grid.

Therefore the future of the electricity market lies in approaching energy as a service and with

some type of aggregators that can capitalise on the flexibility that exists across all of the

distributed assets (i.e. solar PV, EVs and other storage options etc.), incorporate the utility of

these assets with pricing signals from flexibility markets and/or spot-price electricity markets

and could manage these assets (e.g. charging times of EVs, install smart water heaters etc.).

In this context, the service provider will for instance decide one day that the EV charging would

be best suited using the solar PV array in the workplace during the day, while next day the EV

charging would be more beneficial to take place at home over night. In such scenario with an

arbitrage established, the fixed pricing structure could be as low as two thirds of the current

bill, which would be a far more attractive offer to customers rather than continuing the current

market where utilities and other wholesale market actors offer only a few percentage discounts

on a third of customers’ electricity bill for switching to that commercial actor in a zero -sum

market place. In this environment, the grid’s main purpose would evolve into addressing peak

load since base load would be covered locally. Since this kind of transition would certainly

disrupt the electricity system, the key question facing the industry is whether the utilities and

other industry incumbents will be leading the destruction of the existing business models or

whether they will resist and create barriers to change. Countries such as Norway which have

ample amount of flexibility in the energy system (including DSR) are uniquely positioned to

serve as a test bed for this kind of energy market system, although a flexibility market on at

distribution level will be required. The risk that countries like Norway will otherwise face is a

situation where they boast a very strong, reliable and cheap renewable electricity system, but

suffer from a cost of transportation of this electricity from production point to end-user that will

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become increasingly more expensive up to a point where it cannot compete with end-users

own local solutions. The future viability of the grid is also being challenged by another trend

that is being seen across Europe where there is a transition towards community ownership of

energy, in terms of means of production, transportation and consumption.

The Need for a Smart Grid for EV Integration

Smart grid technology will play a paramount role in enabling an effective grid management as

more and more EVs come online. A number of Norwegian companies have played an

important part in grid management against constraints and overload. For instance, the

company e-Smart Systems provides an analytically based IT platform that enables electrical

load forecasting (e.g. transformer load, EV charging demand and power demand after outage),

segmentation and profiling (e.g. customer behaviour and households with/without EVs/PVs),

risk monitoring (e.g. data aggregation, power outage risk estimation and me ter error

estimation) and fault & anomaly detection (e.g. identification of components based on image

recognition and detection/locations of errors), via IoT, big data and machine learning. By using

real-time monitoring, this data platform enables better demand management and therefore

reduced grid investment, by providing aggregators with data with up to 1 -minute resolution

from a range of inputs, such as past and present EV charging date, energy price information,

weather info etc.). Although the smart meters only generate values on an hourly basis, the

platform utilises instrumentation in the substation to acquire values on 1-minute basis or use

aggregation of smart meter values from different sources.

On a more granular level, the usage of data on EV charging and loads across individual

household, building or area under a transformer, allows load forecasting to be calculated to

produce input in an optimisation model that enables increased capacity for EV charging or

more effective balancing use of DER. The e-Smart Systems platform enables integration of

data from multiple hardware (e.g. smart chargers) and associated software systems, with

information from local power intake, ToU tariffs, weather data and social media, to forecast

and monitor the charging demand, peak load capacity issues on the grid and available

flexibility, and eventually carry out optimisation calculations and subsequently produce control

plans that can be executed to switch phase on or off. At present, the algorithm has been tested

using customer from Norway, Denmark and the United States (as well as from demo sites in

Germany and Malta). Where the real data is missing or unreliable, the platform algorithm uses

simulated data from gaming platforms. Norwegian utilities have used this kind of smart

platform to automate smart charging via machine learning that enable customers to capitalise

on cheaper tariffs. Norway’s national TSO (Statnet) has also been experimenting with this

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platform within its R&D programme to gain better control the DER (e.g. disconnect at any

given moment if capacity is lacking) via load management, independent of whether it is a EV

charging site, water heater or office building load. In the Northern parts of Norway where the

grid is weaker, this platform is being used to supplement the hydropower capacity to increase

up-time (as there is a lot of down-time due to overload) and reducing the buyback from

industrial customers (e.g. gas generators). The e-Smart System is also currently running a

pilot project (Zero Consumption Project) in the United States in partnership with the TEA -

Energy Authority with the aim to predict transformer load. As part of this work, a recently

completed pilot to predict broken water meter based on smart meter data from water and

electrical metres, eliminated wasted truck rolls by 87% (i.e. maintenance call outs). As such,

the market place is currently being developed and tested, via this power exchange plat form.

While the smart software will play a paramount role in enabling rapid increase in EV

penetration, the hardware will equivalently play a key role for the relevant data collection. For

instance, the Norwegian smart charging company ZapCharger has been developing smart

charging technology that can help reduce the constraints imposed on electricity capacity by

EV use, by providing technological solution that defers upgrading of transformer stations,

support scalability in multi-unit dwellings and car parks, ensures safe and fair use of EV

charging infrastructure. ZapCharger has developed an innovative smart charging technology

helps optimise performance with multiple charging stations via integrated load balancing,

phase balancing, power measurement and electronic ground fault detection, and is currently

developing new functionalities including smart house integration and dynamic load balancing

against the house. According findings by ZapCharger, a single 63A circuit (phase 3) can

charge 5000km worth of electricity per day and therefore 100 cars per day (average car drives

approx. 50km/per day). This means there is significant capacity available even when charging

on a regular circuit without smart solutions. In order to capture this flexibility one of the

technological solution provided by ZapCharger has enabled up to 90% reduction of capacity

required for EV charging compared to traditional solutions. In fact, whereas the capacity

needed to avoid upgrading of the transformer station with 100 static (or “dumb”) charging

stations would be equivalent of 25 households, the ZapCharger Pro would only require

capacity equivalence of two households (based on a 400V grid and 63A fuse). In addition, the

phase balancing technology embedded in the ZC Pro charger enables between 2-5 fold faster

charging by optimising the use of the flexibility in the system. A wall-based flat cabling system

allows for an increasing number of charger installation as demand increases which reduces

infrastructure investment up to 90%. The ZC Pro charger also has an electronic RCD that

enables it to handle ground faults separately (i.e. local safety shut-down under fault conditions)

without the entire system going down and an automatic charger restart after power failure.

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The need for such smart charging technology is highlighted by the fact that the company has

already installed over 800 chargers and made preparations for more than additional 3000

since August 2016, with sales nearly doubling each month. While there are certainly some

crucial contextual differences between Norway and the UK as to how successful the

ZapCharger technology would be to address the capacity challenges on the local grid in the

UK grid with its 1 phase 100A cut-fuse, as opposed to the Norwegian network with 3 phase

LD supply with three 63A cut-out fuses, it could certainly provide some important benefits in

the UK in terms of multi-occupancy buildings that do host 3 phase system and where there is

a need to scale-up charge points and phase balancing is needed.

The Impact on Customer Behaviour

Back in 2011, concerns began to be raised by UK network operators about the electrification

of transportation as there were unknowns regarding likely charging behaviours that may for

example result in excessive evening peak demands.. At the same time, there was also a

strong sense that British customers would absolutely not accept their charging to be controlled

by a third party. However, a recent Ofgem-funded research project (My Electric Avenue) that

was carried out by EA Technology in partnership with UK utilities, debunked both of those

assumptions. One of key findings regarding the former assumption was that the peak demand

was only observed for around 30% of the charging capacity installed, with diverse patterns of

charging at other times of the day. The conclusion was that for every kW of charging capacity

installed onto a distribution network, on a diversified level there is only need to design a

network by a factor of 30%. This means that for every 7KW of charging capacity installed, the

DNOs do not necessarily have to increase the availability/capacity of their network by

additional 7KW. The reason for this resides in the increasing diversification that occurs with

the scaling up on EV penetration and diversity of use.

In terms of the latter assumption, the study also showed that most people were (anecdotally)

unaware of the curtailment and there was broadly a large amount of flexibility within a large

time window. For instance, in one of the studies where 100 EVs (Nissan LEAF) which were

often curtailed quite aggressively, there was only a single case where this curtailment may

have been found to have an impact resulting in insufficient charging (although it was uncertain

whether this was directly due to the curtailment rather than mismatch in driving demand in

relations to EV storage range). Another major finding of the study was that there were a

number of commercial and regulatory barriers identified in ways that differ from the Norwegian

model. For instance, since EV chargers up to 7KW are classified as an appliance and therefore

within the standard connection which the customers already have, they could install a 32amp

charger and with no mandatory requirement notify the network operator. This results in a

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passive role for the DNO where it cannot identify when people make their transition to EVs

and therefore the network operator will not have the mechanisms to either spot this transition

ahead of need (i.e. and therefore anticipate any increase in peak load due to EV adoption) or

actually influence those customers by installing smart charging or upgrading their connection.

One of the key outcomes from the study’s modelling exercise on what the distribution networks

look like in terms of capacity available, was that at 50% penetration level on a household level

30% of low voltage circuits/feeders will be operating above their rating and therefore require

reinforcing. However, the distribution networks differ substantially across regions regarding

their capacity to accept EV penetration onto the grid.

Another interesting result relates to flexibility markets and V2G potential, which indicated that

for around 80% of EVs on 7KW charging for a 50-mile round trip only require approximately

two hours of charging. This means there is significant potential for flexibility as it was observed

that over 90% of vehicles are plugged in overnight for eight hours of more. The study also

highlighted a very high share of charging taking place at home which puts the greatest

pressure on DNOs.

The daily and seasonal variability of electricity consumption at a time where there is steadily

increasing penetration of renewable energy into the system, means that there is a critical need

to better understand and forecast people’s electricity consumption as the transportation

system becomes electrified (this balancing challenge will be exacerbated as the electrification

of heating takes place in parallel). It’s important to understand how consumers interact with

the energy system in the context of the low carbon transition - particularly individual’s

responsiveness to different types of managed charging proposition. The Energy Technologies

Institute has recently been involved in a £5million collaborative research project called

Consumers, Vehicles and Energy Integration (CVEI) which aims to gain better understanding

of the changes to market structures and energy supply system needed to support high

deployment of plug-in vehicles, as well as the technical implications of these changes and how

people might respond to them. The project consisted of two parts: a charging behaviour trial

and a vehicle uptake trial. The behaviour trial assessed response to different tariff propositions

(user-managed and ToU tariff versus supplier managed charging versus no-managed

charging) among 240 consumers over two months with parallel BEV and PHEV trials. The trial

used data on use and charging with additional questionnaires and choice experiments to

survey peoples’ attitudes towards the three charging regimes based on their experience to

help inform service providers on how to best manage their system. By providing 200

customers with four days with one of each of three different types of vehicles (BEV, PHEV and

ICE), the vehicle uptake trial aimed to explore the preferences across different types of low

emission vehicles and estimate the relative share of different vehicle types on the road in a

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zero or very low emission transportation scenario in 10-20 years’ time, as well as gain better

understanding of the wider macroeconomic issues around EV uptake. A combined set of

modelling tools was developed to provide an integrated, holistic means of quantifying and

qualitatively assessing the impacts on and from infrastructure, consumers, vehicle uptake and

use, policy measures and commercial models across the system. According to the interim

findings, one of the biggest challenge for EV as far as consumers are concerned is to narrow

the gap around the cost of low emission vehicles as capital cost in seen as the major barrier

to EV adoption in the near- to medium term. This is actually a misguided perspective given

that most EVs are “purchased” on lease arrangements that are very similar in cost to ICE

vehicles, with further savings on running cost.

Low emission vehicle uptake can also result in a sizable drop in government revenues.

Furthermore, while a moderate uptake of low emission vehicles can be expected even with

limited Government intervention, the existing incentives do not encourage rapid enough

uptake of EVs to meet decarbonisation targets. The interim results also indicated that the

economic benefits of car sharing can have a significant impact on the cost of travel on per

mile/km basis and is likely to have material benefits to consumers. Amongst adopters to date,

there also seems to be a changes in the “main” and “second” car dynamic with EVs being

driven comparable mileages to ICEs. According to the findings, consumers’ charging

behaviour was found to be far more influenced by convenience rather than cost of charging

and therefore the pricing differences need to be substantial in order to influence peoples

charging behaviour. The consumer research also scoped the dynamics within multi-car

families and whereas it was previously expected that EVs would become “the second car”

within a family househo0ld for shorter journeys, the results showed this not to be the case as

the EV became more frequently used than expected with mileage comparable to ICEs. There

was also a recognition that awareness of public charge points are perhaps more important

than actual availability.

The Potential for V2G

At present, the five largest EV storage/battery technology developers are patenting around

13,000 patents per year, which target cost reduction, durability, weight and energy/volume

density of storage. Needless to say, the world will look very differently in 5+ years as the

technology rapidly advances forward. One of the biggest promise of the EV world is the

potential of V2G but one of the key challenge is to bring together these two very different

sectors which operate at very different timescales. For instance, while the automotive industry

works in line with a 2-3 years in business model development with a 12 year, the charge point

operators are looking working with technology with a 5-year life cycle, and the benefits of smart

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charging and V2G for system efficiency are numerous. This includes deferral of grid

reinforcement and increased charger density on weak networks, via local response to voltage

fluctuation or client site power restriction, as well as commercial electricity bill minimisation

(e.g. triad period avoidance). Furthermore, an EV also has the potential provide grid balancing

(via an aggregator) services, such as energy arbitrage and peak shaving/shifting, firm

frequency response and short term operating reserve, as well as provides a commercial case

for managed charging, which in turn can extend battery life by keeping the battery in a lower

state of charge (since conventional method leaves batteries for the longest periods fully

charged which is suboptimal for battery life). However, perhaps the strongest case for V2G is

that it will support and optimise local renewable generation.

Cenex has been engaged in a research programme that has developed a Matlab-based

simulation model called EV Analysis Environment (EVA). The EVA simulation environment

deploys a vehicle simulation tool-chain that consists of: a data summaries tool to filter and

analyse both charging and vehicle usage data into summaries of journeys with charging and

V2G events (with key characteristic summarised cycles extracted to create representative

drive cycles); and a backward facing vehicle model to calculate fuel consumption (and hence

CO2) from drive cycle input. The EVA programme also relies on EV modelling extensions,

including i) an equivalent circuit model (i.e. a battery electrical model) to calculate electrical

characteristics and SoC of EV battery based on power cycle input, using charge/discharge

efficiency and temperature, ii) a battery degradation model that calculates capacity fade and

increase in internal resistance of an EV battery due to age, temperature and powe r cycles

(and hence SoC), and iii) a motor model that assesses performance and efficiency for traction

motors to allow simulation of EV operation. Finally, the EVA simulation programme also

utilises a V2G Energy Model that calculates energy profile possible with V2G operation using

aggregated vehicle date for a number of V2G support scenarios, and a V2G Economic Model

that calculates the economic viability of V2G for each scenario based on the energy profile

and demand requirement profile. Both models integrate information on vehicle journey,

building demand, renewable generation and market demand, and in turn outputs cost analysis

summary relating to building, vehicle and market economics.

Initially the EVA programme relied on historical data as input but moving forward it will use

real-time data from a number of projects that Cenex is participating in. One of these, EFES is

a 3-year academic-industry based R&D project that explores the technical, social,

interoperability and market barriers of V2G in the UK by developing i) a cloud-based virtual

power plant (VPP) that is capable of utilizing electricity storage assets (e.g. batteries or EV)

through a software package, controlled by electricity providers, ii) a V2G unit which EVs can

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plug into to provide both charging for the vehicle and enable it to act as a battery storage,

either to provide electricity directly to a building or the National Grid using the VPP, and iii) a

V2G Gateway that provides the control functionality for the V2G unit, enabling the unit to

communicate with both a building and the VPP to determine the most appropriate charging or

discharging option. Some of the interim analytical work suggests that through utilizing just 6%

of their car park, the project partner Manchester Science Park could save over £14,000 per

annum through V2G implementation, together with bidding into energy markets (e.g.

wholesale electricity markets or short term operating reserve) potentially providing additional

income equivalent to around £60 per month for each vehicle integrated into the scheme.

The Intelligent Transport, Heating and Control Agent (ITHECA) is another R&D demonstration

project carried out by Cenex that showcases the collaboration of transport, frequency

response services, energy storage and district heat solutions to establish the potential of V2G

to maximize a combined heat and power (CHP) plant. This demonstration work is based

around the European Bioenergy Research Institute at Aston University where the UK’s first

V2G unit has been installed. Together with Aston University, Cenex has been working on

maximizing outputs from the CHP unit through V2G management and intelligent control of

vehicles with the aim to establish the business case for the operation of these technologies as

a collaborative energy solution. The project has helped establish the technical requirement of

installing and managing V2G to support CHP output and local electricity demand, helped

setting out the economic case of increasing CHP output through increasing and decreasing

electrical demand in response to the needs of the plants and the operational conditions of V2G

based on real-world testing and operation of a fully-functioning V2G in order to share and

disseminate lessons learnt.

Other projects which Cenex has been participated in includes Smart Mobile Energy, a

feasibility study that explores the business case for integrating V2G technology at building,

district and city scale across three pilot cities, Birmingham, Berlin and Valencia; and the

Interreg North Sea Region funded SEEV4-City programme which is establishing long-term

demonstration pilots on the integration of local renewable generation and energy storage by

using ICT to manage energy supply and demand flow, in line with clean electric transport

services and other mobility services.

Compiled by Mikael Mikaelsson – UK Science & Innovation Network

For further information please contact: Mark Thompson – Senior Innovation Lead – Energy

Systems, Innovate UK - [email protected]