IEEE Electrification - June 2019 - 47

Grid Considerations for
Large-Scale EV Integration
In August 2018, one of every 10 new vehicle purchases in
California was an EV. As EV adoption has implications for

power systems, we discuss the challenges for the distribution grid and what is currently being done by utilities to
prepare for the electrification of passenger vehicles.

Characteristics of EV Load Demand
At a macro scale, EVs appear to pose only a modest burden on the electric grid. The California Energy Commission estimates that 3.9 million EVs could add 15,500 GWh
of energy demand, equivalent to just 5% of California's
current total annual energy demand. However, at a micro
scale, EVs represent a significant addition to traditional household loads. In 2018, PG&E recorded that the
average peak demand-the aggregate demand from residential customers divided by the number of customers-was approximately 1 kW/household (the 1 kW
value includes the natural power smoothing across several customers and does not reflect the maximum
instantaneous peak demand at the household level). By
comparison, most EVs commonly charge at 6.6 kW with
a level 2 charger. At an average of 37 mi driven per day,
an EV in the United States consumes approximately
10 kWh/day, which is a significant portion of the 17.5 kWh
of average daily household consumption in California. A
typical EV charging period at residential locations starts
between 4 and 7 p.m. and coincides with the grid peak
demand observed around 8 p.m. Therefore, in terms of
energy consumption and power demand, an additional
level 2 residential charging station is similar to an additional house on the grid.
In terms of geographical distribution and density, EV
adoption is not expected to be evenly distributed across
all distribution grids. On the contrary, EVs are typically
found in clusters, as demographics and peer pressure are
key factors when buying an EV. Some disparities will exist
regionally. For instance, the National Renewable Energy
Laboratory (NREL) map of EV density shows that the

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penetration of renewable energy sources by 2045. Both
trends are creating challenges for distribution grids, which
traditionally have been designed to incorporate a number of
large power plants connected to the transmission network to
serve a predictable aggregated load made up of many small
customers. The rise of distributed energy resources (DERs),
such as fast-charging stations for EVs and solar panels, is disrupting the predictability and homogeneity of distribution
grids. As a result, it is necessary to evaluate grid planning,
operation, reliability, and rate plans/tariffs.
This article discusses how the distribution grid infrastructure can be adapted to accommodate the electrification of passenger vehicles. We show the impact of
uncontrolled EV charging on 39 real-world distribution feeders in Northern California and then extrapolate the results
for a larger set of more than 1,000 residential feeders within
the service area of the Pacific Gas and Electric Company
(PG&E). Our objective is to determine what, if any, special
requirements are needed to accommodate EV loads and
whether charging stations can be installed within the existing network without additional direct control structures or
indirect control mechanisms, such as economic incentives.
We provide recommendations for reducing the costs associated with adapting the distribution grid for demands related
to the shift to EVs. Although many scientific papers have
included impact analyses about EV integration, they often
use prototypical feeder models and synthetic data as the
input for simulations. We believe that investigations using
actual distribution feeder models from regular utility operations can provide more realistic results and better inform
strategic investment and planning decisions.

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IEEE Electrification - June 2019

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