IEEE Power & Energy Magazine - March/April 2022 - 78

in my view (continued from p. 84)
Power System Flexibility
[T]here is broad industry consensus
that regional transmission
organizations (RTOs)/ independent
system operators (ISOs) will
need more operational flexibility
... to reliably serve loads as the
resource mix evolves to include
more weather-dependent variable
energy resources (VERs) ....
-Federal Energy Regulatory
Commission Staff Paper
Docket Number AD 21-10000
(September 2021)
In every U.S. ISO/RTO except PJM,
variable wind and solar are expected to
supply more-in some markets much
more-than 30% of total energy by 2030.
The rapid growth of variable renewable
resources is being driven by the 90% drop
in the unsubsidized cost of utility-scale PV
and a 70% decline in the unsubsidized cost
of onshore wind since 2009. On an energy
basis, building new wind or solar generation
is often less expensive than operating
existing coal-fired generation and is becoming
competitive with natural gas. At the end
of 2020, solar, wind, and energy storage
projects made up more than 90% of the
capacity in U.S. interconnection queues.
VERs present significant challenges.
In several markets, wind and
solar energy will provide nearly all the
energy required in some hours, while
meeting only a small portion of energy
requirements in others. Rapid, often
difficult-to-forecast changes in the output
of wind resources have required
the Midcontinent Independent System
Operator and the Southwest Power
Pool to each compensate for declines
in wind generation of 8 GW within
4-hr periods. With VERs providing
28% of energy, the California ISO has
had to offset 3-hr ramps exceeding
15 GW. Without the immediate response
of balancing resources, such variability
can produce rapid changes in power
flows and impact system stability.
Flexible demand can offset this
variability. A 2019 Brattle Group study
estimated that
78
ieee power & energy magazine
the United States will
add more than 120 GW of new, costeffective
flexible demand by 2030, in
addition to 16 GW of new, conventional
demand response. The additional flexible
demand could provide benefits in
excess of US$15 billion per year. Much
of the increase in flexible demand
could come from smart thermostats,
water heaters, and building management
systems. Smart technology can
shift the timing of power consumption
without impacting consumers by taking
advantage of the thermal inertia
inherent in the 38% of U.S. electricity
consumption devoted to cooling,
heating, ventilation, and refrigeration.
Additional flexibility will be available
with increases in the adoption of electric
vehicles, electrification of home
heating, and deployment of intelligent
industrial and agricultural control systems.
Smart systems can shape, shift,
and modulate flexible demand, often at
a cost that is below the cost of battery
energy storage. Intelligent systems can
also optimize the operation of batteries
and other behind-the-meter DERs.
Smart technology will require changes
in how customers participate in power
markets. Existing demand response
programs pay customers for reducing
demand compared to a recent baseline
period. Smart technology will anticipate
demand response events and increase
baseline usage to maximize incentive
payments. Moreover, smart devices will
respond to simple time-of-use rates with
rapid, discrete, potentially destabilizing
spikes in demand when prices drop.
In large regional markets, system
operators dispatch several hundred to a
few thousand generators. In a distribution
system with millions of intelligent
end-use devices, hundreds of thousands
of electric vehicles, and hundreds of
megawatts of distributed generation
and storage, dispatching DERs will
become computationally intractable.
Centralized dispatch may be limited to
large and operationally critical DERs.
Operators will have to rely on price signals
to integrate most of the DERs.
Fundamental economic principles
provide a road map for developing retail
rates that
incorporate the necessary
dynamic prices. An efficient and
equitable rate design should have the
following three components:
1) A dynamic spot market or marginal,
cost based price. The European
Union's 2019 electricity
directive requires larger electric
suppliers to offer rates that
clude spot-market prices.
in2)
Recovery of the utility's remaining
transmission and distribution
revenue requirements
in differentiated, fixed access
charges. Many European electric
utilities require consumers
to subscribe to one of several
demand-based access charges.
This approach offers an incomeprogressive
alternative to recovering
fixed utility costs in
kilowatt-hour rates.
3) An insurance component for
customers who want high-bill
protection.
In a client study, we analyzed two
years of advanced metering data from
more than 450,000 customers and illustrated
how such three-component,
real-time pricing rates could benefit
most of the consumers, protect lowincome
customers, and align with accepted
equity principles. An efficient
and equitable rate design could accelerate
the development of new demand
and DER management services, optimize
flexible demand, and provide efficient
incentives for DER development
and operation.
Realizing the potential of demand
and DER flexibility requires efficient
pricing and smart technology.
Field experiments are needed to test
the performance and customer acceptance
of different combinations of
dynamic pricing and smart technology
as well as alternatives that might
combine simpler rate designs with
demand and DER management services.
The results of such experiments
march/april 2022
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