IEEE Power & Energy Magazine - May/June 2020 - 21

Proposing Tariffs of Tomorrow
Of course, tariffs have been slow to adapt in part because
of technological limitations. As Bonbright recognized, costreflective rates require having the necessary metering infrastructure in place, and, for decades, this infrastructure was
only available to large commercial and industrial customers.
For residential and smaller commercial and industrial customers, it was less expensive and easier for utilities to simply bill
metered kilowatt-hour usage, despite the resulting issue of
fixed-cost recovery. However, the widespread deployment of
smart meters is making it much more affordable to measure
demand, even for residential customers. As this change progresses, the implementation of cost-reflective rate designs for
all customers is becoming more accessible than ever before.
Given these advances, the tariffs of tomorrow are likely
to consist of three parts corresponding to the three elements
that comprise electricity costs: a fixed monthly charge, a
time-varying energy charge, and a demand charge.
The fixed charge (sometimes referred to as a customer
charge, service charge, or facilities charge) is expressed in
dollars per month. It reflects the costs of servicing the customer, such as billing, metering, and customer service.
The time-varying energy charge, expressed in U.S. dollars per kilowatt-hour, recovers energy costs, either in the
form of a simple time-of-use (TOU), critical peak pricing
(CPP), variable peak pricing (VPP), or real-time pricing
(RTP) rate. A simple TOU rate defines peak periods during
which prices are higher than in off-peak periods and is currently the most common form of time-varying rate. However, programs like CPP, VPP, and RTP are considered purer
forms of dynamic pricing in that they are based on actual
market conditions and thereby a better signal of customer
changes in the utility's costs.
The demand charge, expressed in dollars per kilowatt,
recovers grid capacity costs, typically based on peak electricity consumption over a span of 15, 30, or 60 min. It may
be either coincident or noncoincident. A coincident demand
charge applies to a customer's peak electricity consumption
at the time of the maximum system usage, whereas a noncoincident demand charge measures a customer's highest
usage during the month, regardless of the time of day.
Some critics of noncoincident demand charges argue that
they do not reflect the utility's cost structure, since they may
not coincide with the capacity costs driving system peak and
the need for new infrastructure where beneficiaries should
pay. Many of these critics favor time-varying energy charges
without any demand charges. However, these two charges
are not at odds and can be offered simultaneously to supplement one another. While time-varying energy charges can
dynamically recover energy costs and encourage load shifting, noncoincident demand charges for residential customers
can recover distribution-related capacity costs and encourage overall greater efficiency. After all, customers expect
electricity service whenever they need it, at any time of the
day. As a result, a utility must build adequate infrastructure
may/june 2020

to meet a customer's peak usage, regardless of when it
occurs. However, a noncoincident demand charge effectively
serves as a proxy for the localized cost of connecting a customer to the grid.
Another option for recovering the costs of the grid is to
increase the fixed charge, but a fixed charge may not fully
account for a customer's size or send price signals the way
that both coincident and noncoincident demand charges can.
The implementation of a demand charge further addresses
the equity criterion by minimizing cross-subsidies from customers with high load factors to those with low load factors,
who may have a low kilowatt-hour consumption but a high
kilowatt demand that a volumetric rate cannot capture.
In terms of the cross-subsidy from non-DG consumers
to DG consumers, one solution recognizes the unique features of the manner in which such customers interact with
the grid, as exemplified by their load shapes, and to price
electricity accordingly. Thus, utilities in a number of states
are now asking their commissions for permission to establish a new class for prosumers and to price electricity to
them in a manner that reflects the cost of serving electricity
to them.
The creation of a separate class may discourage the adoption of rooftop solar and other DERs. Cost-based, three-part
tariffs may also encourage the adoption of certain technologies like electric vehicles by enabling time-varying rates that
give vehicle owners the option of charging vehicles during
the less-expensive off-peak periods. Neither outcome is inherently wrong. Rather, regulators need to understand that a more
advanced rate design requires a greater understanding of outcomes. Rate design is not always the place to incent technologies. Other policies outside of those applying to rates can do
this, for instance, through tax credits, rebates, or renewable
energy certificates.

Obstacles to the Future
Undoubtedly, given the diversity of customer tastes and
expectations, these new tariffs will not appeal to all residential customers. Risk-averse customers might resist the volatility of time-varying rates and the risk implicit in demand
charges. Utilities can offer these customers rate options that
better suit their risk profiles, while still incorporating the
cost-reflective concepts underpinning the tariffs of tomorrow. Possible rate options are listed in Table 2.
From among these many options, the most risk-averse
customers would likely go with a guaranteed bill, which is
constant regardless of the volatility in their load profiles or
their electricity prices. On the other hand, risk-taking customers would likely go with a RTP rate that, on average,
would likely give them a lower average price. Each of these
rate options presents a unique tradeoff between the bill savings that customers would experience and the risk that they
would be exposed to in the form of bill volatility. When they
are plotted out in the savings-risk space, they yield an "efficient pricing frontier."
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IEEE Power & Energy Magazine - May/June 2020

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