IEEE Power & Energy Magazine - March/April 2022 - 28

to a 2021 CEC Joint Agency Report. Figure 1 shows the
projected impact of high building and transportation electrification
on annual energy consumption in California
through 2050, representing an increase of nearly 100 TWh
per year. Climate mitigation strategies will put increased
stress on the T&D systems and will require widespread
and costly upgrades to keep up with the growing electricity
demand, simultaneously increasing the value proposition
for NWA solutions.
Valuation Frameworks for
DER-Based NWA Solutions
This section summarizes DER valuation frameworks that
incorporate the cost and benefits of NWA solutions, such
as T&D capacity deferral, resilience, and/or reliability
services to overcome the limitations of more traditional
DER frameworks.
Valuation of T&D Investment Deferral Benefits
Accurately valuing transmission and distribution deferral
benefits in DER valuation methodologies is crucial for identifying
localized project opportunities for DER-based NWA
solutions in place of traditional T&D upgrades. Accordingly,
the CPUC's Integrated Distributed Energy Resources proceeding,
which focuses on increasing the use of demand-side
resources to better serve the electricity system, has led to an
additional proceeding devoted to the development of a standardized
DER valuation methodology for use in California.
This led to the development of the Avoided Cost Calculator
(ACC), which is an annual modeling process to quantify
benefits associated with demand-side resources over a specified
planning period.
The ACC model incorporates value derived from the
avoided costs of all of the activities associated with generating
and distributing electrical energy. These costs are then
simulated for each hour of each year in the study period.
Figure 2 illustrates 1) the types of costs included in the
model (avoided GHG in blue, energy in green, generation
capacity in yellow, transmission capacity in brown, line
losses (not visible), distribution capacity in red, and costs
due to methane leakage in light green); and 2) the changes
that have occurred to the model over the last three iterations
(2019-2021).
The 2021 version of the ACC assumes that the marginal
unit of generating capacity in the evening is utility-scale
storage, which will have a significantly lower cost and GHG
emissions profile than the previously modeled marginal unit,
a gas combustion turbine. Therefore, DERs are replacing a
less expensive, lower-emitting storage unit in the evening
hours with highly effective load-carrying capacity, reducing
its replacement value. In addition, the 2021 version uses a
production cost model to simulate future prices rather than
using historical price trends, which assumes lower energy
costs in future years, further reducing the avoided cost.
The ACC standard framework is not required for utili100
200
300
400
500
600
Year
Hydrogen
Production
Building Electrification
Other Transportation Electrification
Electric Vehicles
Baseload, Net of Energy Efficiency
figure 1. The projected demand growth in California
through 2050 in high electrification scenario. (Source:
Energy and Environmental Economics, 2021.)
28
ieee power & energy magazine
ties to use as part of DIDF NWA solicitations. For these
procurement cycles, utilities may conduct their own costeffectiveness
analysis, which has traditionally not been
made public. Implementing a standard framework that is
transparent and compulsory for solicitation may help push
more projects through the contracting process. The SOC
mechanism may be a step in this direction. Under this
mechanism, the utility communicates upfront what it is
willing to pay for a particular DER service or product and
thus defines a target for DER providers to aim for. The
2022 cycle will be the first to include an SOC solicitation
so it is yet to be determined whether this concept will
help deliver more DER projects for distribution investment
deferral.
For the IOU Partnership Pilot, the burden of DER valuation
falls on the ESPs selected by the utilities. Under this
framework, utilities define a circuit-specific budget using
85% of the cost of the estimated conventional upgrade cost
to procure DER capacity for distribution upgrade deferral.
Since the utility has already defined its willingness to pay
for DER/DR-based NWAs, so it is up to the ESP to determine
if the value set by the utility will be sufficient to justify
a project and/or if there are additional value streams available
to earn revenue from these same assets (i.e., wholesale
market participation).
There are also still significant limitations in cost/
benefit modeling in the face of extended climate-related
power outages. The ACC does not assign any value to
march/april 2022
Load (TWh)
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2040
2042
2044
2046
2048
2050
IEEE Power & Energy Magazine - March/April 2022

Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - March/April 2022
