ASHRAE Journal - April 2015 - 65

TECHNICAL FEATURE

utility commission. Typically, the amount of kW assessed
on each monthly bill is based on the highest 15- or
30-minute kW interval within that billing period. Utility
demand charges are the most widely understood among
commercial customers because they are easiest to intellectually comprehend, and also very often the most
transparent form of demand charge on a customer bill.
There are several complexities to navigate when
deciphering utility demand charges, however. The
first is time-of-use or seasonal adders. Many summerpeaking utilities have summer adders: in New Jersey,
the utility PSE&G levies an annual demand charge
for commercial customers year-round; in the months
June through September there is an adder that effectively triples the total utility demand charge. Another
demand charge adder is based on time-of-use. For
example, Southern California Edison (SCE) has one
rate with a summertime on-peak demand charge
adder during the weekday hours of 12 to 6 p.m. of
$26.01/kW, as well as a mid-peak adder of $7.17/kW, for
the site's peak during weekday hours of 8 a.m. to 12
p.m. and 6 to 11 p.m. These two charges are in addition
to SCE's year-round off-peak demand charge of $14.32/
kW.1 All of the California investor-owned utilities have
rates that model this format.
Another source of complexity in utility demand
charges is the use of ratchets. Many utilities use ratchets to assess a higher kW number to commercial customers. Oncor, one of Texas's largest utilities, imposes
an 80% ratchet for large users. In Oncor's case, the
ratchet works as follows: a customer's assessed kW is
the greater of a) its monthly peak kW draw, or b) 80%
of the peak kW draw over the course of the previous
11 billing months.2 This penalizes customers who hit
a particularly high kW peak in any given month, as
that peak can affect their electricity expenditure for
the next year. For example, if a customer has a typical
monthly peak kW of 2,500 kW, but happens to hit a peak
of 5,000 kW in the month of August, its energy costs
will be affected for the following year: even if the customer never exceeds 2,500 kW in any 15-minute interval
again, its assessed demand for the next 11 months will be
a minimum of 80% of its August peak, or 4,000 kW.
A final, and perhaps most confusing, source of complexity in utility demand charges is pricing based on
load factor. Load factor is defined as the average kW
draw divided by the peak interval.

FIGURE 1 Nine ISO/RTOs in North America. Source: FERC.

138.8 kW Average
500 kW Maximum = 27.7 Load Factor
Other utilities use a more tortuous method referred to as
hours use of demand (HUD). A simple glance at an HUDbased bill might give most customers no idea that they are
sensitive to peak demand fluctuations; but HUD actually
serves as a very expensive form of demand charge.
For its large C&I customers, Georgia Power's PLL-9 rate
has no $/kW demand charge, but rather has an hours use
of demand structure that, if understood, functions as an
incentive for buildings to shave their daytime peak.3 The
best way to explain Georgia Power's rate is by example.
Suppose you had a very small building - perhaps a large
doghouse or a toolshed - which has a steady 1 kW load all
month. At the end a 30-day month you would have used
720 kWh. With Georgia Power's PLL-9 rate and a 1 kW peak
load, the first 200 "Hours Use of Demand" would charge
you 12.7 cents for the first 200 kWh and the remaining
520 kWh would be at a little more than a penny per kWh.4
Using the same example - with the exception being that
for 1 hour of the month the load went up to 2 kW and for
one hour the load was zero - the total kWh would be the
same 720, however now the first 400 kWh (2 kW x 200
HUD) would be at 12.7 cents, and the balance at 1.3 cents.
Therefore, the one single hour of increased demand
doubles the amount of electricity charged at the higher
rate. After surcharges and taxes, Georgia Power's effective
demand charge for PLL-9 customers is in excess of $20/
kW monthly - and it is 95% ratcheted.

Grid Demand Charges
Independent System Operators (ISOs) and Regional
Transmission Operators (RTOs) are both terms to
APRI L 2015

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