IEEE Power & Energy Magazine - March/April 2022 - 45

Operationalizing the LMV
Calculation for a DER Rebate
This VDER framework expresses the locational value of
a kilowatt of real power injection and kilovar of reactive
power injection at each hour. These effects are expressed
in terms of their marginal impact on all of the capacity
costs for all violations needing corrections in that hour. For
practical purposes, the approach averages the nodal values
into single area-wide values to determine the DER
rebate value.
A five-step process allows us to work from the DER value
framework to generate a standard, area-wide value downstream
of the substation or mitigated overload. In practice, we can use
these values to induce customer participation in incentive programs
that bring DERs onto a local distribution network (substation
or feeder) where the DERs will mitigate adverse conditions.
These averaged values avoid the need to establish specific incentives
that are localized to each customer site.
The LMV calculation follows a five-step process, as
illustrated in Figure 3:
1) Quantify the locational impacts through a power flow
sensitivities analysis.
2) Calculate the deferral value of the avoided cost of the
capacity to violated locations.
3) Allocate the deferral value of the avoided cost of the
capacity to violated locations.
4) Multiply the two quantities to get the LMV.
5) Average the nodal values to a single area-wide value.
These area-wide values will still be based on granular
node-level calculations to determine the locational
VDER necessary to incentivize DER adoption in place
of traditional system upgrades. This will avoid customer
confusion that may result from publishing nodal values
for DER rebates.
A framework is necessary for auditing the DER response
performance. The DER response must be recorded in real
time, and an analysis should be planned to contrast utility
and third-party DER management performance. This measurement
and verification plan must be conducted at regular
intervals, characterizing individual events and summarizing
across aggregated events.
In practice, measurement and verification capabilities
depend upon additional software and hardware that augment the
buildout required to bring a VDER framework into the field.
The VDER measurement and verification require a real-time
communication infrastructure,
information technology infrastructure,
bandwidth, field equipment, and software systems.
Software typically resides in a master station where it can communicate
with sensors, substation equipment, and DER metering
devices. These devices must be robust to cybersecurity
threats and environmental conditions.
Implementation Considerations
and the DER Management System
The presented framework for valuation is a way to evaluate
the capability of a specific DER to respond to grid constraints
based on location, performance, and generation
profile. While this capability is significant in assigning
a value, the realization of the value is far more important
from the grid reliability and resilience standpoint. Once
a constraint arises, the DER must replace the traditional
grid asset and mitigate the constraint for those specific
hours. For a simple PV system, the real power output is
simply driven by the sun. However, the reactive power
output may be adjusted by local drivers, such as the voltage
based on the smart inverters' droop (reactive power)
controls or set points provided by a supervisory system.
For storage systems, solar and storage combination, and
other dispatchable resources, the coordination of the real
and reactive power outputs can be determined from the
prevailing system conditions and again communicated to
individual devices.
To implement coordination beyond a few devices, a reliable
low-latency, high-bandwidth communication system is
required to allow each device to follow a particular control
signal. At the same time, establishing the appropriate control
requires a resource management technology that identifies
grid constraints, implements set point changes, and
Step 1a
Step 1b
Hourly Power
Flow Solution
Step 2
Deferral Value of
the Avoided Cost of
Capacity
Power Flow
Sensitivities
Step 3
Locational and
Temporal Cost
Allocation
figure 3. A single area-wide value calculation.
march/april 2022
ieee power & energy magazine
45
×
Step 4
Nodal and Hourly
LMV (US$/kW,
US$/kVar)
Step 5
Area-Wide
LMV (US$/kW)
IEEE Power & Energy Magazine - March/April 2022

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