IEEE Power & Energy Magazine - March/April 2017 - 34

A component of that integration is to identify optimal locations
where DERs can be best integrated to provide the greatest benefit
to the entire electric system.
including energy efficiency, demand response, solar PVs,
and various types of distributed generation and energy storage. Some of these technologies may be attractive for reducing peak demand at the distribution level (and therefore
supporting the deferral of traditional investments) but
may be less likely for customers to implement in a noncontrolled scenario.
For the scenarios considered, each utility constructed an
example portfolio of DERs based on DER characteristics,
customer characteristics, and estimates of DER costs from
previous deployments. A portfolio of DERs and their costs
were specified, with each reflecting local climatic and customer circumstances. The composition of the respective portfolios is illustrated in Figure 6. The simulations deployed the
DER portfolio to nodes as a normalized (kilowatt) resource
available to resolve violations. For consistency and transparency, well-defined rules direct the DER allocation in a manner consistent with the study objectives.

Using DERs Instead of Traditional
Utility Investments
Network System Study Results
The base-case analysis for the network system revealed thermal overload violations during the ten-year planning time
frame. Each of these conditions requires remediation, typically addressed through traditional upgrades such as cable
replacements and transformer replacements. Two methods
were examined to resolve these violations. The first of these,
utility-side resolution, employed established practices and

Fuel Cell
15%

Storage
9%

CHP
6%
Solar PV
12%

traditional system upgrades to mitigate the identified violations in the year they manifest. The second method employed
a DER solution, strategically locating DERs where needed
to mitigate violations.
For this analysis, the amount of DERs allocated to a node
was not allowed to exceed the node's peak load to prevent
backfeeding the network protector. Because the analysis
also assumes that DERs can be physically placed at the designated node locations, the required DER amounts can be
regarded as the most optimal solution as it is the minimum
amount of DERs that resolves the system constraint.
The placement methodology for this scenario assigns
DERs in relatively small increments, permitting violations
to be resolved in a precise manner. In contrast, traditional
utility-side investments generally result in additional capacity (headroom) to accommodate unanticipated load growth
and growth beyond the planning period. Distribution planners aim to build headroom (typically 10%) into system
upgrades to avoid having to resolve the same constraint each
successive year to meet incremental annual load growth on
the system. For example, 20-30% headroom was achieved
with the network transformer upgrades in the traditional
remediation solution. This approach is consistent with utility
system practices and, to some extent, results from the nature
of electric system equipment that is available only in relatively large increments of indivisible capacity. Consequently,
to provide a more meaningful comparison of the DERs and
utility-side solutions, a second DER alternative was conducted where an equivalent 10% headroom was achieved for
each of the constrained assets.

Demand
Response
9%

Storage
20%
Energy
Efficiency
49%

(a)

Solar PV
29%

Energy
Efficiency
26%

Demand Response
25%

(b)

figure 6. The (a) Con Edison and (b) SCE case study portfolios.
34

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march/april 2017

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