IEEE Power & Energy Magazine - March/April 2022 - 36

For flexible demand to realize its value in five to 10 years,
viable programs need to start today, along with sustainable
business models, that demonstrate their performance
in the field.
Utilizing DERs Requires Visibility and Control
While the IDRP study shows the theoretical value of
DERs, the reality of capturing that value is complex.
Since DERs are typically behind or at the customer meter,
most utilities have little control or visibility of what these
devices are doing. Indeed, many utilities also have limited
visibility to the concurrent status and loading of
individual distribution circuits and feeders. To utilize the
flexibility and control options for DERs, both the visibility
of the distribution system and the ability to control
individual DERs or groups of DERs are necessary.
In other words, having both an ADMS and a DERMS is
important to fully utilize and control DERs. SMUD is
currently implementing ADMS and DERMS capabilities
that will enable the capture of DER value and control the
risks that they introduce.
Capturing DER Values Requires
a New Approach to Planning
Most California utilities expect to see continued strong
growth of DERs. The electrification of transportation and
buildings is a policy priority and will be the main driver of
load growth for the next several decades. At the same time,
this new load cannot be treated or forecasted in the same
manner as done in the past. With electrified buildings and
transportation, there are more opportunities to manage the
load so that the system costs of supporting it can be minimized.
If successfully managed, DERs can increase the load
factor on our distribution systems, defer upgrades, increase
reliability, and save money for customers. However, to capture
these values, improved planning as well as new tools
and methodologies are needed.
Historically, many utilities, including SMUD, have used
a simple distribution planning approach based on the utility's
actual annual system peak, which is then normalized
to account for weather conditions and converted to a lowerprobability
but higher-impact event, such as a once-in-every10-years
peak load. Planning is based on the " unmanaged "
load where only the historical trend of DERs is considered
and, often, not future growth. The forecasted peak load is
then distributed across subareas of the distribution system
using historical data and expert judgment, and deterministic
load flow scenarios are modeled for the peak demand hour
of the year under consideration.
There are two main reasons why this approach must
change. First, it may not lead to a cost-effective outcome
because it does not consider the impact of future DER
growth and value DERs can have in controlling and
modifying the peak load. Second, despite the investments
that are identified using this method, the reliability may
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ieee power & energy magazine
deteriorate because some DERs can increase the load
and could have a disproportionate impact on subsets of
the distribution system that could be missed if the DER
growth is not explicitly forecasted. To better capture the
value of DERs and modernize distribution planning to
meet the needs of the changing grid, three areas of opportunity
are discussed in the following section.
Load Forecast
The simple distribution planning approach described previously
risks missing both the variability of the load and locational
effects of nonhomogenous DER growth.
DERs and Other Load Drivers
DERs will grow in response to signals unrelated to the distribution
system and be primarily driven by factors such as
demographics; income level; the cost of DER technologies;
subsidy levels; and, perhaps, local political, financial, and
regulatory support for DERs. For example, one city might
provide tax rebates for those who install batteries and help
accelerate or simplify permitting, whereas another may have
a less accommodating approach. All of these factors will
contribute to an uneven load growth, which translates into a
varying impact on substations and feeders.
DER growth may also change the load shape so that the
timing and duration of peak load events are different compared
to history. When doing long-term distribution system
planning, it is essential to consider these factors. This
means a top-down, systemwide load forecast may need to
be replaced-or at least complemented-by a bottom-up
locational forecast that captures different growth expectations
in the service territory. As these patterns emerge, they
may also open opportunities to strategically incentivize
DERs in areas where they could help alleviate constraints
or defer upgrades.
Managed Versus Unmanaged Load
Distribution planning forecasts usually use unmanaged
load as the basis for planning. This means that future customer
behavior load impacts beyond those already reflected
in the historical load data series are not included in the load
forecast. Managed load, on the other hand, includes customer-influenced
behavior, such as energy efficiency forecasts,
the demand response, solar PVs, and customer-sited
batteries. The practice of using the unmanaged forecast
becomes problematic when many of our expected drivers
of load growth and shape are not in the historical record,
including the acceleration of energy efficiency and demand
response, uptake of EVs, and electrification of behind-themeter
energy uses. A sophisticated managed forecast is,
therefore, essential to capture these load impacts.
Net Load and the Variability of Net Load
The sum of the base underlying electric demand and
emerging impacts of the demand response, energy efficiency,
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IEEE Power & Energy Magazine - March/April 2022

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