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

Background
The electrification of transportation will play a critical role for the UK’s ambitions to meet its
legallybinding 2008 Climate Change Acttargetsof80% reduction in GHG emissionsby 2050.
This transition to the electrification of personal transportation has commenced and is steadily
securing its foothold of success, as an increasing number of countriesmove 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.

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

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 strategyis 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%
renewablesfromhydropower,the cityof Oslo is currentlyon a journeyto 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% fromlight freight.While the bulk ofemissions came frompersonaltransportation,or 39%,
surprisingly high carbon emissions of 30% were identified coming from construction
machineries. Assuch,Oslo is making inroadson the electrification ofconstruction 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 city 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

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 ofenergyuse locallyand in the main grids.The main grid’sconnection
to the micro energy systems will allow greater energyexchange between energy vectors, and
to receive and deliver energylocallyto and fromthe main energygrids – both in terms of water
based (i.e. for heating and cooling) and electric based systems. This work will strengthen the
connectivitybetween energyand buildingson one hand,and energyand transportationon the
other hand.
Fortum Charge & Drive is currently the utility in the world with the highest share of EVs’
penetration amongstits 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 hasled 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
additionalcapacity,particularly atlocallevels where the grid is relativelyweak.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 nowbecome 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 networkoperatorsand systemoperators,islargelydriven bycompetition
atthe energyretaillevel.In the UK there are binding climate commitmentsand 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 gasboilers and there is no effective roadmap available to drive forward

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 energyretailer/generator perspective,EVswill play a keyrole 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 opportunitiesto be provided
from EVs on a local community level to enable a local energy system. Another difficult
challenge is to identify where taxrevenues will come from a transportation system defined by
EVs.
The electrification of transportation is taking place in a context of transportation culture thatis
already in flux. The number of private vehicles in the UK is at an historical height with
approximatelyone vehicle per householdalthough mileage usagehasreducedby1500km/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 isa plugin car grantthatpartlysubsidisesthe purchase ofEVs.
OLEV also runsa communication strategycalled Go-Ultra Lowto 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

next few years. At present, there are around 12.000 charging points across 3000 locationsin
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
approximately70 garageswith around 100 EVbusesper garage..In termsof the smartenergy
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
capabilityatpresent.However,in the UK there are concernsofhowto ensure thatthe 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
last10-15 yearsthere have been significanteffortsto strengthen and reinforcethe 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’ dayin 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.

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
capacityfor EV charging asmany customers assume theywill need greater capacitythan they
actually do. Therefore, it is important to get in place the right charging infrastructure to enable
automated charging thatensuresthe rightchargingpattern since mostcustomerswillnot 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 capacityfor smart charging and therefore instead of installing 150x20A 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 possibilityto deliver demand side response efficientlyand 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 operatesa smart grid supplying and
managing electricity to 700,000 customers with a facility on their web site so homeowners can

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 metersin comparison reportdata
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’scharging 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 hoursor overnight.
While there is a growing consensus on the importance of ToU tariffs in order to influence
peoples’charging behaviour,some challengescould arise fromthe factthattwo differentprice
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-
marketsignal which could have a significantimpact 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 howactions on one system impacts the other system, via data exchange and
use of software platforms to provide visibility (albeit no control).

Furthermore,there are some concerns that the construction of a pricing structure based on
today’s load could become troublesome if it indeed successfully 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 tariffsthat 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 inform
customer case handlersand customers howto 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 industryactorshowever,these concernsaboutpeakdemand mayperhaps
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
stationsatthe workplace is considered likelyto mitigate thisproblemeven 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 customerbehaviour,itisdifficultfor 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 asthe onlyoption on the table as it is more reliable

and better managesrisk. Therefore, the most attractive option to avoid the potential challenge
around coinciding peakdemands(i.e.acrossEVand other domesticelectricityuse) isto adopt
a managed charging regime where customers will not be actively responsible for the “smart”
charging schedule.Fromthe perspective ofthe DNO’s,this kind a technicalintervention 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 representsthe 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 smart
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 available, optimal angles for

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 lowPV-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 thiscontext,the service provider willfor instance decide one daythatthe 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
marketwhere utilities and other wholesale marketactorsoffer onlya fewpercentage 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 electricityfrom production point to end-user that will

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,EVcharging demand and power demandafter 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 meter error
estimation) and fault & anomaly detection (e.g. identification of components based on image
recognition and detection/locationsoferrors),via IoT,big data and machine learning.Byusing
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 subsequentlyproduce control
plansthatcan be executed to switch phase on or off.At present,the algorithmhasbeen 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

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 platform.
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 newfunctionalities including smart house integration and dynamic load balancing
against the house. According findings by ZapCharger, a single 63A circuit (phase 3) can
charge 5000kmworth ofelectricityper day and therefore 100 carsper 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
enablesitto handle ground faultsseparately(i.e.local safetyshut-down under faultconditions)
without the entire system going down and an automatic charger restart after power failure.

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 thatBritish customerswould absolutelynotaccepttheir 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 capacityinstalled, 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 commercialand regulatorybarriersidentified in waysthatdiffer from the Norwegian
model.For instance,since EV chargersup to 7KWare classified asan 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

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 ofthe keyoutcomesfromthe study’smodelling 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 hoursofcharging.Thismeans there issignificantpotentialfor flexibilityas 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 ofrenewable energyinto the system,meansthatthere 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
responsivenessto differenttypesofmanaged charging proposition.The EnergyTechnologies
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
deploymentofplug-in vehicles,aswell as the technicalimplicationsofthese changesand how
people might respond to them. The project consisted of two parts: a charging behaviour trial
and a vehicle uptake trial.The behaviour trialassessed response to differenttariffpropositions
(user-managed and ToU tariff versus supplier managed charging versus no-managed
charging) among 240 consumersover two months with parallelBEV 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
customerswith four days with one ofeach of three differenttypesofvehicles(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

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 resultsshowed 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 Potentialfor 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 lookingworking with technologywith a 5-year life cycle, and the benefits ofsmart

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 EValso hasthe potentialprovide grid balancing
(via an aggregator) services, such as energy arbitrage and peak shaving/shifting, firm
frequency response and shortterm 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 power cycles
(and hence SoC),and iii) a motor model thatassessesperformance and efficiencyfor 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 marketdemand,and in turn outputscostanalysis
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 Cenexis participating in. One of these, EFES is
a 3-year academic-industry based R&D project that explores the technical, social,
interoperabilityand 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

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 IntelligentTransport,Heating and ControlAgent(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 businesscase for the operation of these technologies as
a collaborative energysolution.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
electricaldemand in response to the needsofthe plantsand the operationalconditionsofV2G
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 - mark.thompson@innovateuk.gov.uk

UK - Norway plugin vehicle roundtable summary report

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UK - Norway plugin vehicle roundtable summary report