New Approaches to Current Problems in

Electric Utility Rate Design

Carolyn Brancato*

I. INTRODUCTION

The generation of electricity is usually accompanied by a variety
of detrimental effects on the environment, including increased air,
thermal and radiation pollution, use of increasingly scarce fuel re-
sources, and degradation of land devoted to the siting of generating
and transmission facilities. Environmentalists have argued that re-
duction in demand for electric energy is necessary to minimize
these adverse environmental impacts.' They have also questioned
the basic economic assumptions under which electric energy is sold
by calling into review utility pricing mechanisms whereby the larg-
est users are given quantity discounts. They contend that this prac-
tice induces greater consumption of electric energy and results in
increased environmental harm.

Recently environmental groups have employed an additional,
more successful argument to force regulatory commissions to re-
view rate design practices. This argument is based on indications
that the quantity discounts and other traditional rate design prac-
tices are no longer cost-justified and, therefore, should be aban-
doned. Needless to say, significant attention has been focused on
the cost justifications for the total revenue and the corresponding
charges to customers which a utility is permitted by the regulatory

* Professor of Economics, Lehman College, City University of New York. The
author was formerly a member of Governor Carey's Task Force on Energy, and has
testified on behalf of the New York State Attorney General before the New York
State Public Service Commission.

1. See, e.g., Brief for Sierra Club and Students Hot on Conserving Kilowatts as
Intervenors, Potomac Electric Power Co., Case 568 (Phase I), 95 P.U.R.3d 99 (D.C.
Pub. Serv. Comm'n., May 9, 1972); Brief for Citizens for Clean Air, Inc., as In-
tervenor, Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491 (Sept. 6, 1973); Brief
for Environmental Defense Fund as Intervenor, Niagara Mohawk Power Corp., Case
26402, 14 N.Y.P.S.C. 120 (Feb. 5, 1974).

40



Problems in Electric Utility Rate Design

commissions. However, a secondary focus on cost justification of
rate design, i.e., how the rate increases granted are to be appor-
tioned among customers, has assumed unprecedented prominence
in recent regulatory proceedings.

Challenges to traditional rate design practices have been launched
by a broad-based alliance. In addition to the environmentalists,
who are concerned with mitigating unnecessary growth, this al-
liance includes residential consumers who are concerned not only
with increased bills but also with the allegation that they are
subsidizing large commercial and industrial customers. Even some
utility management personnel, under severe pressure to meet capi-
tal expansion needs at peak periods, while facing loss of earnings
due to energy conservation measures, are advocating redesign of
the rates.

Thus, widespread support has emerged in favor of revising the
traditional "quantity discount" pricing practices. The substitution
of "peak pricing" practices would serve to assess more accurately
charges to residential and business customers according to the de-
mands and costs which they impose on the system. Other rate
design alterations flow from this proposed reorientation of elec-
tricity pricing, including methods to reevaluate costs among cat-
egories of customers and rates that will reflect estimated future
incremental costs of generation.

This Article initially explores the historic economic justifications
for traditional rate design practices and the changes within the
electric utility industry which have undermined those justifications.
It then examines the alterations in rate design which have been
implemented by regulatory commissions throughout the country.
Finally, the economics of rate redesign and some of its implications
are analyzed through an examination of this new type of rate
structure. At the very least, a new rate structure will produce
rates more closely related to the costs of service. Viewed more
broadly, however, rate redesign has the potential to curb pressure
on utilities to expand their facilities, thereby significantly easing
the burdens on the environment. In turn, as fewer, more costly
plants are required, consumers will benefit by a reduction in the
rate of increase in utility bills and a fairer allocation of costs
among customers. Last but not least, utility managers will face
less critical financing pressures.

41



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

II. A REEXAMINATION OF THE HISTORIC JUSTIFICATIONS

FOR TRADITIONAL RATE DESIGN TECHNIQUES

A. Pricing Within the Electric Utility Industry

An electric utility provides service to its customers at rates which
are regulated by the state public service commission in whose juris-
diction the utility operates. The commission establishes what it
considers to be a fair overall rate of return on the invested
capital which the utility employs in providing electricity to its
customers. Based on this rate of return, the commission establishes
the amount of gross revenue which may be earned to enable the
utility to recoup the rate of return after operating expenses are
met. Issues of rate design are primarily concerned with how the
pie of base rate revenue responsibility is to be allocated among
customers.

Pricing within the electric utility industry is complicated by
the fact that the industry serves a public whose demands may
vary throughout the day as well as throughout the year. Since
electricity cannot be stored, a utility must design its generating sys-
tem to meet maximum peak demand. The utility, therefore, con-
structs different kinds of plants to meet varying demand require-
ments. The first is the "base load" facility, generally a large (i.e.,
200 to 1,000 megawatts) fossil-fuel, hydro or nuclear unit intended
to operate more or less steadily throughout the year except for
periods of scheduled maintenance. Smaller, less capital-intensive
"peaking" units are added, during certain periods in the day or in
certain seasons of the year, to serve higher loads as customer de-
mand increases to a maximum or "peak." These peaking units are
often steam-powered electric units or gas turbines whose capacity
may be in the vicinity of 100 megawatts (MW). They may be
added in small increments to the "base load" facility to meet the
total demand.

The base load equipment, while more capital-intensive, is gen-
erally more efficient than the peaking equipment in terms of op-
erating costs (including those attributable to utilization of fuel
resources). A unit's "heat rate" equals the quantity of fuel input
in British Thermal Units (BTU's) required per kilowatt-hour
(kwhr) generated. Thus, the lower the heat rate, the more effi-
cient the unit. To illustrate, during the winter of 1971-72 on the

42 [2: 40



1975] Problems in Electric Utility Rate Design 43

Consolidated Edison Company's system in New York City, the
base load fossil-fuel units had an average heat rate of 10,300 BTU/
kwhr. During the same period, the less efficient steam peaking units
realized a higher average heat rate of 15,600 BTU/kwhr, whereas
the gas turbine units averaged 14,800 BTU/kwhr.

The pricing system which evolved within the industry to account
for variations in costs of equipment utilization distinguished three
elements of expense: (1) capital, or fixed costs; (2) operating
expenses, or variable costs which do not include fuel costs; and
(3) variable fuel costs. These expenses are reflected in the three
types of charges paid by customers: (1) "demand" charges per
kilowatt (kw) of capacity, which correspond to the capacity-re-
lated fixed charges of plant installed; (2) "energy" charges per
kwhr, which correspond to the variable non-fuel component of
operating expenses; and (3) "fuel adjustment clause" charges per
kwhr, which cover variable fuel costs beyond the amount included
in base rates. In addition, a minimum charge is made for "cus-
tomer" services to cover the cost of billing and metering both
energy and demand charge schedules.3

2. Testimony of Bertram Schwartz, Record at 1103-09 and Exhibit 132-A, Consol.
Edison Co., Case 26292, 14 N.Y.P.S.C. 1213 (Aug. 19, 1974).

3. Base rates in the traditional pricing system are obtained in the following
manner. First, the total energy charge component is calculated by adding the
minimum charge for energy service to the price per kwhr multiplied by the quantity
of kwhr. Then the minimum charge for demand service is added to the price per
kw multiplied by the quantity of kw to achieve the total demand charge. The
energy charge plus the demand charge equals the base rate. Then the fuel adjust-
ment clause charge (i.e., the price of fuel per kwhr multiplied by the quantity of
kwhr) is added to the base rate to arrive at the overall charge. Thus:

TRb = (C, + P.Q.) + (Cd + PdQ.)
TRf = (PfQ.)
TR = TRb +TRf

where,
TRb = total revenues from base rates, i.e., from demand and energy charges, ex-

cluding fuel adjustment clause charges.
TRf = revenues from fuel adjustment clause charges.
TR = total company revenues.
C. = customer costs or minimum charges for energy or kwhr service.
P. = price of energy charges for kwhr provided.
Q. = quantity of kwhr provided.
Cd = customer costs or minimum charges for demand or kw service.
Pd = price of demand charges for kw provided.
Qd = quantity of kw provided.
Pr = price of fuel adjustment clause charges per kwhr provided.



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

Customers are typically grouped into service classifications ac-
cording to their usage patterns. Generally, separate classifications
exist for residential, commercial and industrial users. Customers in
residential classifications normally pay only energy charges, while
larger commercial and industrial users pay both demand and energy
charges. All customers pay fuel adjustment clause charges.

Although electricity was originally sold at a uniform rate per
kwhr, soon quantity discounts, whereby the price per kwhr de-
clined as usage increased, were established as a means of encourag-
ing consumption.' Until recent public service commission rulings,
there were within virtually all service classifications on a typical
electric utility system substantial quantity discounts for larger
"blocks" (i.e., ranges of usage) for both demand and energy charges.
Thus, the more electricity consumed, the cheaper it cost per unit of
demand, expressed in terms of kw, or per unit of energy, expressed
in terms of kwhr. The fuel adjustment charges are not usually sub-
ject to quantity discounts and are "flat" or equal for all kwhr
consumed.'

The practice of offering reduced block rates in the base rate struc-
ture was sustained by a classical economic theory which held that
there were economies with respect to both short- and long-run pro-
duction and distribution of electricity which should be reflected in
reduced electric rates for increased consumption.

To understand the evolution of pricing within the industry, it is
necessary to distinguish among three essentially separate notions
of system economies within an electric utility system. First, there
may be short-run decreasing costs due to the fact that once an
investment in facilities is made, output can be increased with unit
costs declining until the physical capacity of the facility is reached.
Thus, the short-term variable cost phenomenon for which energy
charges are established relates to fuller utilization of existing ca-
pacity.' For instance, once a 1,000 MW base load plant is built,
variable as well as fixed costs per unit of output will be lowest

4. C.F. PHILLIPS, JR., THE ECONOMICS OF REGULATION 351 (1965).
5. Id. at 356 and n.6.
6. A. KAHN, THE ECoNoICs OF REGULATION, PRINCIPALS AND INSTITUTIONS 124

(1971). See also V. Smith, C. Cicchetti & W. Gillen, Electric Power Regulation,
Externalities and the A-J-W Effect, a paper presented at the Seminar on Problems
of Regulation and Public Utilities, Amos Tuck School of Business Administration,
Dartmouth College, Aug. 26-30, 1973.

44 [2: 40



Problems in Electric Utility Rate Design

if the plant is operating at the maximum 1,000 MW level of output.
If output were only 300 MW, then the cost for each unit would
be 1/300 of total fixed and variable plant costs instead of 1/1,000
of the total costs (which would be the unit cost at capacity). Also,
up to a point, variable costs per unit of output will probably decline
as the number of workers and other variable inputs reach the level
for which the operation was designed.' It should be noted that
the short-run case assumes a fixed technology and a fixed time
period, and is therefore a "static" phenomenon.

Quantity discounts for demand charges are partly sustained by
the short-run decreasing cost phenomenon, but are bolstered by
the second economic consideration of long-run decreasing costs.
Here again a fixed technology and a given time period are assumed.
If long-run economies are present, then the unit cost for a larger
plant, if operated at its optimum (which is generally at its maxi-
mum rate), is less than the unit cost for a smaller plant, and
economies of scale or increasing returns to scale are present. It has
been asserted that the long-run decreasing cost phenomenon con-
stitutes the primary justification for considering some public utility
operations "natural monopolies."8 In the literature of regulatory
development, the efficiency with which one company could supply
a market with larger, lower unit-cost plants was critical in justi-
fying elimination of competition. Not only would facilities not be
duplicated, but unit costs would be lower for the industry as a
whole.9

A third economic consideration pertaining to the utility system
is presented when a technological breakthrough occurs which lowers
unit costs. Although this does not strictly fulfill the economist's
notion of economies of scale, which assumes a given technological
level, it nevertheless may result in "system-wide economies" by

7. KAHN, supra note 6, at 124.
8. Id.
9. Even if this unit cost structure were changed, there would still remain other

reasons to continue large-scale monopoly operations. They include: (1) lower reserve
capacity requirement per unit of system load (interconnections with other systems
add to the reliability of service); (2) smaller total plant capacity per unit of cus-
tomer demand because of the effect of diversity among the loads of large numbers of
customers of various classes and businesses (large industrial loads are advantageous
in this respect); (3) the ability to hold surplus capacity to a minimum when
providing for increased loads; and (4) lower cost of supplies when purchased in
large quantities. See R. CAYwOOD, ELECTRIC UTILITY RATE EcoNOHES 15 (1956).

1975] 45



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

shifting outwards the production function itself (i.e., a greater MW
output is obtained with the same unit cost).

The fuel adjustment clause was designed to allow the utility to
recoup current increases in fuel expenses (or, in the case of a de-
cline in fuel costs, to pass savings to customers) automatically,
rather than having to wait for changes in tariff rates which require
lengthy proceedings. Fuel costs above a base amount are charged
to customers as they arise, allowing for accounting lags. For ease
of computation, the total allowable fuel costs generally are divided
monthly on a per kwhr basis. All customers are charged an equal
or "flat" rate for each kwhr they use.

When fuel costs were an insignificant portion of a customer's
bill, this practice seemed not only efficient but reasonably equitable;
more precise calculations to reflect variations in BTU efficiency
and fuel consumption during peak and off-peak periods would have
yielded only insignificant alterations in rates paid. But in recent
years, especially during the fuel shortages of the 1973-74 and 1974-
75 winters, fuel costs have escalated rapidly, and a need has arisen
to scrutinize the rate design of the fuel adjustment clause to sys-
tematically incorporate variations in fuel costs resulting from use
at times when the system is more efficient or less efficient.

B. Reevaluating Base Rates

Throughout most of the history of electric utilities the three pre-
viously mentioned economic phenomena have occurred: short-run
decreasing costs, long-run decreasing costs due to economies of
scale, and system-wide economies due to new technological offer-
ings. The pricing system which incorporated quantity discounts for
large use, either in terms of capacity costs or demand charges or in
terms of variable costs or energy charges, was appropriate. At the
least, encouraging consumption to fill the excess capacity of the
fixed plant would result in lower average unit costs for all cus-
tomers. To the extent that such encouragement of consumption
would raise demand so as to require additional facilities, this sys-
tem would result in building larger, lower unit-cost plants and aver-
age costs would again decline. Recent evidence, however, indicates
that while the first type of economy (short-run decreasing costs)
may still pertain in certain, although more limited instances, the
two latter types of economies (long-run decreasing costs due to
economies of scale, and long-run decreasing costs due to system

[2: 4046



Problems in Electric Utility Rate Design

economies) appear to have been exhausted-at least for the pres-
ent.'o The quantity discount pricing mechanism which was de-
signed to cover a three-fold decreasing cost situation appears to
be outmoded. Pricing to reflect a more limited, short-run decreasing
cost phenomenon may now conflict with pricing to reflect a long-
run increasing cost phenomenon which has recently developed.

To a certain extent, increased usage of kwhr benefited the old
system since idle plant was put to use and excess capacity was
minimized. If usage were encouraged to the extent that it exceeded
existing capacity and new plant was needed, no significant problem
was posed as long as long-run costs were declining. However,
when usage in off-peak periods (such as for electric heating)
caused spillovers into peak periods, where there was no excess ca-
pacity, the system had to adjust by increasing capacity, which
recently is no longer of the declining-cost variety. If the increased
usage could be confined to off-peak periods when excess capacity
exists, then energy charge quantity discounts could be justified to
cover the short-run decreasing cost case. However, since quantity
discounts may encourage usage to spill over into peak periods as
well, a review of the promotional practice is in order.

The experience with light water nuclear power plants (LWR)
from 1961 through 1975 is indicative of the significant cost trends
within the industry, since most of the new generating units which
have been added in recent years have been this type of unit rather
than the traditional fossil-fuel plants. The bulk of the new gen-
erating capacity slated to be added in the near future, moreover,
will be of the LWR-type, unless larger delays with the units and
significantly more cancellations ensue. At the lower end of the
size spectrum, as the size of the plant increases, cost per kw de-
clines. For instance, two units under 100 MW in size cost over
$450 per kw (in 1971 constant dollars), whereas plants in the 500-
700 MW range cluster in the $100-200 per kw cost range. However,
as a certain level of size is attained-somewhere over 500-600 MW-
unit costs do not appear to fall significantly, if at all. Plants over
800 MW experience a $100-200 per kw cost similar to the smaller
units." It appears, therefore, that long-run decreasing costs due to

10. See text accompanying notes 46-119 infra.
11. Olds, Nuclear Standards and Standard Nuclear Plants: More Than Money is

at Stake, 79 PowER ENG. 42, 44 (March, 1975).

471975]



48 COLUMBIA JOURNAL OF ENvmhONMENTAL LAW

economies of scale are lessening and that economies of scale are
either exhausted, minimized, or obscured beyond a 500-600 MW
range. Moreover, the average unit costs for all the LWR's going
into commercial operation from 1971 through 1975 dramatically
increase as size increases.12 From 1971 to 1975, the per kw cost in
constant dollars has accelerated more than 17% per year, in spite
of the fact that the 1975 plants are 215 MW larger in average size
than the 1971 units.13 Thus, as one writer has put it, "[e]conomy
of scale, if it exists, has been totally obscured by larger offsetting
factors."'4

The trend towards higher unit costs is apparent even when a
mixed fossil-fuel and nuclear system is considered. For example,
on the Consolidated Edison Company's system in New York City,
the following unit costs were estimated:

TABLE I
CON EDISON CAPACITY COSTS

1969-1975

Total Estimated
Year on Cost $/kw

Facility Line (Current $)

Arthur Kill No. 3 (Fossil) 1969 $148
Indian Point No. 2 (Nuclear) 1973 208
Roseton No. 1 (Fossil) 1973 208
Bowline No. 2 (Fossil) 1974 218
Astoria No. 6 (Fossil) 1975 285
Indian Point No. 3 (Nuclear) 1975 433

Source: Brancato, Con Edison's New Rate Structure: A Breakthrough in Electricity
Pricing, 1 N.Y. AFF. 76, 81 (Spring 1974).

Gas turbine peaking units were projected to be added at $200-240
per kw (current dollars) in the late 1970's; but, even removing the
effects of price inflation, it is clear that the bulk of the company's
new additions have significantly increased unit costs compared to
formerly operating plants. Furthermore, the new plants will be re-
placing some older plants on the Con Edison system, such as those
at Kent Avenue and Sherman Creek, which have lower imbedded
costs per unit. This will raise still further the average unit costs.'"

12. Id.
13. Id. at 44-45.
14. Id.
15. Brancato, Con Edison's New Rate Structure: A Breakthrough in Electricity

Pricing, 1 N.Y. AFF. 76, 81 (Spring, 1974).

[2: 40



Problems in Electric Utility Rate Design

The trend to long-run increasing costs is expected to continue.
LRW plants scheduled for completion in the early 1980's have
1975 projected costs of $750-800 per kw." Furthermore, since costs
for the technological innovation termed the liquid metal fast breeder
reactor (LMFBR) can only be described as exorbitant, the ad-
vent of new technology is not likely to be much of a saving grace.
The American Hallam and Fermi LMFBR's, the former just under
100 MW and the latter just over 100 MW, cost approximately $750
-1,200 per kw.17 The European Phenix, with a cost estimated at
$500 per kw, is approximately 250 MW in size, and a larger Phenix
unit of 450 MW is estimated to cost nearly the same." The Clinch
River Breeder Reactor, the proposed first demonstration LMFBR
in the United States with a commercial production date expected
in the mid-1980's, may approach $2,500 per kw."9

C. Changing Cost Factors in the Electric Utility Industry

The conversion of the electric utility industry from a long-run
decreasing cost industry into an essentially long-run increasing cost
industry will create a marked deviation in its historic economic
profile. A series of higher cost pressures have been exerted on the
industry which have remained uncompensated by economies of
scale or by technological improvements. Higher costs of new plants,
beyond those merely due to increased inflation, have resulted from
emerging trends in several important areas.

1. Financing. The electric utility industry has experienced a
series of pressures which have hindered its ability to finance ex-
pansion. To begin with, it is a very capital-intensive industry. It
has the highest investment per dollar of annual sales of any in-
dustry-$4.18, for example, as compared to $2.85 for the telephone
industry.20 While all industries have experienced severe inflation
as they try to expand, the electric utility industry has been espe-
cially affected. Pressure on its basic capital-intensity status has
been exacerbated as it has attempted to cope not only with inflation

16. Budwani, Nuclear Power Plants: What it Takes to Get Them Built, 79 POWER
ENG. 38, 39 (June, 1975).

17. Olds, supra note 11, at 45.
18. Id.
19. Id.
20. U.S. FEDERAL POWER COMMISSION, TECHNICAL ADVISORY COMMITTEE ON

FINANCE, THE FINANCIAL OUTLOOK FOR THE ELECTRIC POWER INDUSTRY, NATIONAL

POWER SURVEY [hereinafter cited as FINANCIAL OUTLOOK] 51 (1974).

1975] 49



50 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

but with transition to a more highly capital-intensive nuclear tech-
nology. And while inflationary pressures have increased costs of
production inputs such as labor, the costs of capital are rising more
rapidly.

Pressure to expand plant facilities has come from the surge in
demand for electricity due to increased use of electric services such
as air conditioning and electric heating. Also, as electric rates were
experiencing a long-term decline, industry replaced low-energy-use,
high-labor-cost industrial processes with increasing automation. This
has placed substantial demands on the electric utility industry to
construct new facilities, which in turn are often the more capital-
intensive nuclear units.

The rate of construction expenditures within the electric utility
industry has increased from $3.6 billion per year in the 1950-54
period to $17.7 billion per year in the years between 1970 and
1974. And expenditures during the period 1975-79 are projected
to be $27.5 billion per year.2 1 This increase in turn has compelled
the industry to raise more capital for expansion in the capital mar-
ketplace. During 1960-64, the industry financed 59% of all its con-
struction funds internally and only 41% externally. By 1970-74, only
33% of construction money was internally generated, and 67% was
obtained from external sources.2 2 Because the industry is using more
external financing, it is particularly exposed to the recent trend of
increasing interest rates. In the early 1960's, interest rates for public
utility bonds varied from 4-5%, whereas since 1970, the highest-
rated triple A bonds have not sold for less than 7% and have at
times approached the 9-10% range.2 3

Since the mid 1960's and especially since 1970, the rapid expan-
sion of the electric utility industry's external financing, coupled
with rising interest rates, has resulted in serious deterioration of
electric utility company credit. In 1974 alone, credit ratings of 44
major investor-owned utilities were lowered while ratings for only
6 companies were increased.2 4 The deratings have serious implica-
tions for the utilities' ability to float necessary bonds, since many
purchasers of bonds, such as banks and investment accounts, require

21. Id. at 52.
22. Id. at 59.
23. Financial News & Conunent, 95 PUB. UTIL. FORT. 37, 39 (Feb. 27, 1975).
24. FINANCIAL OUTLOOK, supra note 20, at 87-90.

[2: 40



Problems in Electric Utility Rate Design

minimum ratings. Also, it is not only the derated companies which
are affected; an obvious "snowball effect" throughout the credit
market may decrease availability of funds to all electric utility com-
panies and drive interest rates up still further.

2. Environmental Controls. As federal, state and local govern-
ments require industry to install pollution control equipment, the
social costs of environmental degradation are internalized. These
costs are often cited as adding substantially to the increasing costs
of the electric utility industry. The following tables detail invest-
ments made on 500-1,000 MW units for air quality control systems
and for thermal discharge control systems during the mid-1970's
period. They range in air quality control systems from $7 per kw
for nitrous oxide (NO.) combustion modification to a high of $60
per kw for the relatively infrequent process of limestone scrubbing
to remove sulfur dioxide (SO 2 ). Investments made in thermal dis-
charge control systems for fossil-fuel units vary from $3 to $28.90
per kw, and for nuclear units from $4.70 to $45.10 per kw. None
of these costs includes the costs of monitoring and surveillance. In
comparison to total cost per kw of capacity, certain pollution control
devices do not add more than 5% to the basic cost of units, and only
in certain cases where use is infrequent may pollution equipment
contribute up to 30-40%.25

TABLE II

Am QUALITY CONTROL SYSTEMS
RANGE OF INVESTMENT COSTS FOR NEW UNITS (500-1000 MW)

Control System $/kw

Particulate Control

Precipitators $25 - 45
Venturi scrubbers 30 - 45
Bag filters 20 - 40

SO, control

Limestone scrubbing 40 - 60
Lime scrubbing 35 - 55

NO. control

Combustion modification 1 - 7

25. Patterson, Progress in Satisfying Environmental Requirements, 94 PUB. UTIL.

FORT. 13 (Aug. 1, 1974).

1975J] 51



52 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW [2: 40

TABLE III

AIR QUALITY CONTROL SYSTEMS
INCREMENTAL ENERGY COSTS

Control System Mills/kwhr

Particulate control

Precipitators 0.7 - 1.2
Venturi scrubbers 1.0 - 1.3
Bag filters 0.9 - 1.6

SO2 control

Limestone scrubbing 1.5 - 2.2
Lime scrubbing 1.6 - 2.1

NO. control

Combustion modification 0.06 - 0.2

While important, the impact of environmental regulations should
not be exaggerated. A large portion of the escalation in costs has

been due, not to the environmentalists' insistence on a variety of
emission controls and other safeguards, but to the utilities' diffi-

culties in obtaining labor and materials and in making their new

plants work. In its 1970 National Power Survey, the Federal Power

Commission estimated that of a total of 114 steam-powered gen-

erating plants of 300 MW or greater which were projected to be
put in use during the period from 1966 to 1970, only 31 units were
on or ahead of schedule while 83 units were delayed. The Com-
mission analyzed construction delays in the 28 nuclear plants which

TABLE IV

INCREMENTAL INVESTMENT AND ENERGY COSTS - FOSSIL

Incremental Costs

Investment Energy
-Thermal Discharge Control $/kw Mills/kwhr

Off-shore Subaqueous Discharge $ 3.00 0.09
Cooling Pond 5.50 0.14

.Cooling Tower

Natural Draft Evap. 7.25 0.26
Mech. Draft Evap. 4.35 0.20
Parallel Path 5.60 0.26
Fan Assist Evap. 5.70 0.25
Mech. Draft Dry 28.90 1.21



1975] Problems in Electric Utility Rate Design 53

TABLE V

INCREMENTAL INVESTMENT AND ENERGY COSTS - NUCLEAR

Incremental Costs

Investment Energy
Thermal Discharge Control $/kw Mills/kwhr

Off-shore Subaqueous Discharge $ 4.70 0.11
Cooling Pond 7.80 0.16

Cooling Tower

Natural Draft Evap. 11.60 0.41
Mech. Draft Evap. 6.50 0.24
Parallel Path 8.75 0.31
Fan Assist Evap. 8.90 0.32
Mech. Draft Dry 45.10 1.61

Source (preceding four tables): Patterson, Progress in Satisfying Environmental Re-
quirements, 94 PUB. UTIL. FORT. 13, 23-25 (Aug. 1, 1974).

were scheduled to become operational in 1974 and found that 32
plant/months of delay were attributable to public lawsuits or
changes in regulatory requirements, but that 229 plant/months of
work were lost because of low labor productivity, labor shortages,
late deliveries of supplies, breakdowns of components, and similar
technological failures.2 0

3. Labor and Materials Shortages. The rise in labor costs has
been due not only to inflation but perhaps even more to a change
in the variety of skills required to construct and maintain the more
technologically complex nuclear units. While the problems of train-
ing workers should be short-term, they persist even though the con-
struction of nuclear units began well over a decade ago. The lon-
gevity of the problem and the unlikelihood of a quick resolution
make it appropriate to consider this issue as more than short-term

26. U.S. FEDERAL POWER COMMISSION, 1 NATIONAL POWER SURVEY ch. 16
(1970), discussed in Brancato, supra note 15, at 82. For a discussion of environ-
mental consequences related to the siting of plants, such as "thermal discharges to
waterways, injuries to aquatic life, and inroads upon scenic beauty resulting from
the transmission lines made necessary by the remote locations of the plants," see
Jones, An Example of a Regulatory Alternative to Antitrust: New York Utility
Regulation in the Early Seventies, 73 COLUM. L. REV. 462, 527-28 (1973). In addi-
tion to increased costs due to environmental litigation surrounding the siting of
many power plants, one must also consider that industries will choose the least ex-
pensive sites first; thus, a mature industry may be faced with less of a supply of
available land, and that which is available may be of higher cost.



54 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW [2: 40

and to include its economic repercussions in current utility rate-
making.27

While most industry experts believe utilities can in time solve
anticipated skilled labor shortages, they are not as confident that
the electric utility industry will be able to obtain the more tech-
nologically-sophisticated construction materials and equipment on
schedule.2" The anticipated resulting construction delays will con-
tribute to an escalation of costs. If construction of a 1,000 MW
plant is delayed six months, for example, the loss is estimated at
$14,000,000 in interest costs in addition to the loss of working
capital and sales revenue.2 9

4. Availability of Constructed Plants. Outages in plants give rise
to a variety of costs, including direct costs of repair, costs of gen-
erating replacement power, and financing costs which endure even
when a plant is "down." Many of the newer nuclear units have
had high rates of unscheduled unavailability.o For instance, on the
Consolidated Edison system in New York City, during the peak
summer period in 1972, the company's nuclear unit had the highest

27. On April 15, 1974, the Atomic Energy Commission (now the Nuclear
Regulatory Commission) issued an "Action Plan," in which it singled out for com-
ment the shortage of nuclear-qualified welders, pipefitters and electricians. Many
contractors were, in fact, recruiting welders and electricians in Canada to ease the
shortage. Budwani, supra note 16, at 39. Last year, increasing lead times for struc-
tural steel components, carbon steel pipe and valves were reported. A number of
foundries had been closed, exacerbating a critical shortage of casting supply. Id. at
40. Even in early 1975, steel allocations, particularly for heavier gauges and special
shapes, continued to be troublesome, and problems still persist for specialty items
such as steel castings for valves and pumps. Id.

28. Budwani, supra note 16, at 40.
29. U.S. OFFICE OF EMERGENCY PREPAREDNESS, THE POTENTIAL FOR ENERGY

CONSERVATION 33 (1972).
A number of construction delays have been caused by a series of mishaps involving

nuclear units. For example, Con Edison's Indian Point No. 2 has had an extraordinary
series of problems. First, there were numerous difficulties in obtaining skilled labor.
Then, in November 1971, a fire at the plant destroyed a great deal of the control
instrumentation. Repair efforts lasted well into 1972. Brancato, supra note 15, at 82.

In the spring of 1972, Rochester Gas and Electric Co. discharged its Ginna reactor
and discovered defects in the fuel rods, resulting from techniques used in their
manufacture. Since the fuel rods for Indian Point No. 2 had been made using the
same techniques and the same design, and welds in some of the smaller pipes proved
defective in the summer of 1972, Con Edison decided to replace the fuel rods and
undertake a major rewelding program. The plant finally came into service in the
fall of 1973, but by December it was again shut down for repairs. Id. at 82-83.

30. A system's "unscheduled unavailability" measures the unanticipated unavail-
able capacity at the time of the daily system peak.



Problems in Electric Utility Rate Design

unavailability rate of all nuclear units in the country. In 1973, a
Con Edison official testified that there were roughly 30 nuclear
plants in operation in the United States and that, once on line,
they have been available only 60% of the time. This is compared
to fossil-fuel plants of similar size which were in service for more
than 80% of the time.3 '

To compound this problem, nuclear units have design features
which make them difficult to repair when they have trouble. Con
Edison's president, Louis Roddis, Jr., in a 1972 address to the Atomic
Industrial Forum,3 2 noted that even at Indian Point No. 1, a plant
that permits fairly easy access to repair components, a major re-
pair is a "tortuous" event. For example, in May 1970, Con Edison
detected the failure of a thermal sleeve in the reactor's coolant
system. The total effort in locating the failure, analyzing its causes,
designing the remedy and actually making the repair took seven
months. It was estimated that the direct cost of repair was
$1,000,000; the cost of generating replacement power was about
the same.3 3

While some of the causes for the conversion of the electric utility
industry from a long-run decreasing cost industry into a long-run
increasing cost industry, for example, rising labor and construction
costs, may appear to be due to the effects of inflation itself, there
are specific changes in production inputs in order to incorporate
more sophisticated nuclear technology which cause costs to rise
faster than inflationary pressures alone would dictate. In addition,
the persistence of some theoretically "short-run" trends, such as
labor shortages over sustained periods, suggests that "short-term"
may no longer describe a situation which may not be resolved for
years to come and which, until that resolution, will be reflected
in the current rates utilities are allowed to charge. Certainly, one
would expect the availability of nuclear units to improve over time,
as the technology matures and kinks are ironed out. Also, the
present situation of relatively high interest rates and shortages of
labor and materials may change. But it is apparent that, for the

31. Testimony of Bertram Schwartz, supra note 2, at 1176.
32. See Address by Louis Roddis, Jr., President of Consolidated Edison Co. of

New York, before the Atomic Industrial Forum International Conference, Wash-
ington, D.C., Nov. 12-16, 1972, in Brief for Citizens for Clean Air, Inc., as In-
tervenor, supra note 1, at 6.

33. Id.

1975] 55



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

present, the cost structure of the industry has altered in a funda-
mental way. These developments indicate the need to review rate
design to reflect these changes in rates, at least until such time as
the situation alters again.

III. REDESIGNING ELECTRIC RATE STRucTuREs-A REVIEW OF

DECISIONS BY PUBLIC UTILITY COMMISSIONS

Before the turn of the century, regulatory commissions estab-
lished that quantity of consumption may constitute a legitimate and
reasonable basis for discrimination in utility rates. Courts con-
firmed the legitimacy of this precept. In a New York case, Silkman
v. Board of Water Commissioners,14 the plaintiff had objected to
the fact that persons who consumed large quantities of water were
not charged as much per 100 cubic feet as those who consumed
less. The New York Court of Appeals held:

[I]t cannot be said to be unreasonable to provide less rates where
a large amount of water is used than where a small quantity is
consumed. That principle is usually present in all contracts or
established rents of that character. It will be found in contracts
and charges relating to electric lights, gas, private water com-
panies, and the like, and is a business principle of general
application.3 5

A similar position was expressed in 1930 by the Supreme Court of
Errors of Connecticut. Although graduated rates per se were not
at issue, the court, after noting that discrimination in rates is per-
missible if based on a reasonable classification, stated:

Basing the charge of rate by a sliding scale upon the quantity
used is an accepted principle of business administration as ap-
plied to public utility corporations, and this form of classifica-
tion has been upheld by the courts where neither the classifica-
tion nor the rates nor charges were unreasonable.36

The principle that discrimination in rates based upon the quantity
of electricity used may be reasonable, and therefore lawful, was spe-
cifically upheld in a number of cases, including Graver v. Edison

34. 152 N.Y. 327, 46 N.E. 612 (1897).
35. Id. at 332, 46 N.E. at 613.
36. Bilton Machine Tool Co. v. United Illuminating Co., 110 Conn. 417, 426,

148 A. 337, 340 (1930).

56 [2: 40



Problems in Electric Utility Rate Design

Electric Illuminating Co."7 and Steinman v. Edison Electric Il-
luminating Co."

The practice of granting quantity discounts or reduced rates for
increased kwhr use became common and today is generally em-
bodied in statutory form. New York, for example, in Public Service
Law sections 65 and 66, permits rate classifications based upon
the quantity used, the purpose, the time or duration of use, "or
upon any other reasonable consideration.",9 These sections spe-
cifically allow for "just and reasonable graduated rates."4 o

In the early 1970's, state regulatory commissions began to re-
vise electric utility rate structures. They have rejected, to a varying
degree, the earlier justifications for declining block rate structures
and other traditional rate design techniques. This section details
the redesigning of electric rate structures by the various electric
utility commissions. The present redesigning of electric rates has
been achieved through a loose-knit, cooperative effort by several
environmental groups, such as the Center for Law and Social
Policy in Washington (in conjunction with the Sierra Club), Citi-
zens for Clean Air, Inc., the Environmental Defense Fund, and
the Natural Resources Defense Council. As these environmental
groups intervened in suits concerning the various utilities, the re-
spective commissions began to bend in their approach to rate design.

Key decisions have been handed down with respect to the Po-
tomac Electric Power Company,41 Virginia Electric and Power
Company,4 2 the Consolidated Edison Company of New York," De-
troit Edison Company,44 and Madison Gas and Electric Company.4

37. 126 App. Div. 371, 110 N.Y.S. 603 (Sup. Ct. 1908).
38. 43 Pa. Super. 77 (1910).
39. N.Y. PUB. SERV. LAW § 66(14) (McKinney 1955).
40. N.Y. PUB. SERv. LAW § 66(5) (McKinney 1955).
41. Potomac Electric Power Co., Case 568 (Phase 1), 95 P.U.R.3d 99 (D.C. Pub.

Serv. Comm'n., May 9, 1972); Potomac Electric Power Co., Case 568 (Phase II),
95 P.U.R.3d 118 (D.C. Pub. Serv. Comm'n., July 28, 1972).

42. Virginia Electric & Power Co., Case 19027, 95 P.U.R.3d 281 (Va. St. Corp.
Comm'n., June 28, 1972); Virginia Electric & Power Co., Case 19342 (Va. St. Corp.
Comm'n., June 17, 1974).

43. Consol. Edison Co., Case 26105, 12 N.Y.P.S.C. 630 (March 29, 1972);
Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491 (Sept. 6, 1973); Consol. Edison
Co., Case 26538, 8 P.U.R.4th 475 (N.Y.S. Pub. Serv. Comm'n., April 28, 1975).

44. Detroit Edison Co., Case U-4257, 2 P.U.R.4th 188 (Mich. Pub. Serv.
Comm'n., Sept. 12, 1973) (interim rates); Detroit Edison Co., Case U-4257, 3
P.U.R.4th 209 (Mich. Pub. Serv. Comm'n., Jan. 4, 1974) (final rates).

45. Madison Gas & Electric Co., Case 2-U-7423, 5 P.U.R.4th 28 (Wis. Pub.
Util. Comm'n., Aug. 8, 1974).

1975] 57



58 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

The commissions have made rulings ordering the flattening of de-
clining block rate structures and the institution of summer/winter
pricing differentials, a form of modified peak pricing. Certain
commissions have also reevaluated the allocation of costs among
service classifications, and among blocks within service classifica-
tions, in an effort to reflect more accurately the changing economic
conditions within the industry. Finally, issues of energy conserva-
tion and environmental degradation, providing possible beneficial
corollaries to instituting peak pricing based on long-run marginal
costs, have been raised.

A. Potomac Electric Power Company

One of the first cases in which the declining block rate structure
was challenged pertained to an application by the Potomac Electric
Co. (Pepco) for an increase in its rate of return and an increase
in rates for retail electric service." In this case, the Sierra Club and
Students Hot on Conserving Kilowatts (SHOCK) argued for a
restructuring of electric rates. Their arguments focused on rate
design and curbing the promotional activities in which Pepco was
engaged, such as perpetuating a rate structure in which quantity
discounts were given to the largest users. Central to the position
of the environmental intervenors was the argument that all gen-
eration of electric energy is environmentally harmful, and that con-
sumption of energy should be discouraged.47 Sierra Club-SHOCK
also argued that quantity discounts were no longer cost-justified.
The conclusion, therefore, was that, because the growth in the sys-
tem had tended toward increased usage in the higher blocks,
higher increases to higher use blocks were cost justified, since it
is the higher use blocks which contribute to Pepco's need for new,
more costly per-unit output plant additions."9 The environmentalists

46. Potomac Electric Power Co., Case 568 (Phase I), 95 P.U.R.3d 99 (D.C.
Pub. Serv. Comm'n., May 9, 1972).

47. Id. at 115; Potomac Electric Power Co. Case 568 (Phase II) 95 P.U.R.3d
118, 123; Brief for Sierra Club and Students Hot on Conserving Kilowatts as In-
tervenors, supra note 2, at 23-35, 58-61.

48. Brief for Sierra Club and Students Hot on Conserving Kilowatts as Inter-
venors, supra note 2, at 23-24, 58-61.

49. 95 P.U.R.3d at 124 (Phase I); Brief for Sierra Club and Students Hot on
Conserving Kilowatts as Intervenors, supra note 2, at 23-24, 58-61.

[2: 40



Problems in Electric Utility Rate Design

called for a "neutral" rate schedule whereby kwhr charges would
be equal regardless of quantity used."o

The District of Columbia Public Service Commission denied this
request, stating that its judgment in this matter was influenced pri-
marily by the fact that demand for electric energy at the retail
level is price elastic: "[r]emaining unconvinced as we are with
Pepco's costs and load factor, we are not disposed to accept [the
environmental groups'] rate proposals or to prescribe at this time,
on the basis of our own expertise, a wholly 'neutral' rate schedule.""
But the Commission did order a significant change in rate design,
structuring the rate increase so as to impose higher percentage
increases on higher use blocks. The Commission stated:

[A]lthough we recognize that there is testimony of record in-
dicating that increased electric usage has been taking place over
the past several years in all rate blocks, we are persuaded that
the increase granted in this proceeding should recognize the fact
that increased usage in the higher blocks should not result in
disproportionate rate increases in the lower blocks of the resi-
dential rate schedules.52

Many of the positions advanced by the environmental intervenors
were sustained by the Commission in a second case involving Pepco,
two years later.53 In this suit the Commission declared:

We are persuaded by the evidence of record in this case that
low usage consumers have not contributed to the need for the
new investment and the new capacity required by Pepco in
order to meet its public service obligations. We do not believe,
therefore, that low usage customers should be required to bear
the burden of significant rate increases. . . .

We are also aware, as is Pepco, of the current energy crisis and
the efforts being made by government and concerned citizens
to conserve energy. We believe that we have an obligation to do
what we can in this regard to assist and encourage Pepco and
its customers to avoid unnecessary use, without penalizing es-
sential uses of electric energy. We will therefore require that

50. 95 P.U.R.3d at 115 (Phase I), 123 (Phase II); Brief for Sierra Club and
Students Hot on Conserving Kilowatts as Intervenors, supra note 2, at 61.

51. 95 P.U.R.3d at 126 (Phase II).
52. Id. at 124 (Phase II).
53. Potomac Electric Power Co., Case 596, 3 P.U.R.4th 65 (D.C. Pub. Serv.

Comm'n., Nov. 16, 1973).

591975]



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

Pepco eliminate from its proposed rate schedules any increase
on residential customers using 400 kilowatt-hours or less per
month, and to transfer the revenue requirement that otherwise
would be allocated to low usage residential customers to high
usage rate blocks. We suggest, but do not require, that Pepco
accommodate this transfer by eliminating the last rate block
(over 800 kwh per month) of its proposed residential rate
schedule.54

B. Virginia Electric and Power Company

An early case in which the electric utility company argued for
redesigning electric rates involved the Virginia Electric and Power
Company (Vepco)." In 1972, in response to a rate order which
substantially cut a request for a rate increase, Vepco filed new
rate schedules in which it created a new rate block at 600 kwhr
for residential users priced at a higher rate in the summer than
the preceding block. Vepco thus created a U-shaped rate structure
by imposing a substantially greater increase on large users during
the summer peak months than on the other users, while no in-
crease was imposed on users in the preceding rate block (210-600
kwhr)."6 Schedule No. I for Residential Service prior to this ruling
was:57

Monthly Rate for meter readings taken July through October

First 90 kwhr @ 5.04 per kwhr
Next 120 kwhr @ 2.54 per kwhr
Excess over 210 kwhr @ 1.84 per kwhr

After the ruling, the following revised rates were in effect:"

Monthly Rate for meter readings taken July through October

First 90 kwhr @ 5.4904 per kwhr
Next 120 kwhr @ 2.7974 per kwhr
Next 390 kwhr @ 1.7874 per kwhr
Excess over 600 kwhr @ 2.1974 per kwhr

54. Id. at 79-80.
55. Virginia Electric & Power Co., Case 19027, 95 P.U.R.3d 281 (Va. St. Corp.

Comm'n., June 28, 1972).
56. Address by R.H. Hallman, Eighty-fifth Annual Convention of the National

Association of Regulatory Utility Commissioners, Seattle, Washington, September 20,
1973.

57. Virginia Electric & Power Co., Case No. 18759, 83 P.U.R.3d 417, Schedule
I (Va. St. Corp. Comm'n., June 10, 1970).

58. Case 19027, 95 P.U.R.3d at Schedule I.

60 [2: 40



Problems in Electric Utility Rate Design

The U-shaped tariff not only alters the declining block rate structure
but dictates imposition of a summer/winter rate differential where-
by rates charged are higher in summer than in the winter.

In a subsequent Vepco rate case,9 the Virginia State Corporation
Commission approved rates which more firmly established the up-
ward turn in the end-use block rates:60

Monthly Rate for billing months of July through October

First 90 kwhr @ 5.704 per kwhr
Next 120 kwhr @ 2.904 per kwhr
Next 390 kwhr @ 1.854 per kwhr
Excess over 600 kwhr @ 2.604 per kwhr

Fairfax County intervened in this case and argued that large gen-
eral service rates (i.e., those normally accorded to commercial and
industrial users) should be increased more than residential service
rates, and that the Commission's ultimate goal should be to adopt
a single rate for all rate blocks. To accomplish this, Fairfax County
argued that any increase granted should be restricted to the upper
rate blocks.6 '

The Commission accepted this argument in part by finding that
Vepco should increase rates to large general service customers by
a greater amount than for small general service customers. Resi-
dential customers did not receive a proportionately lower rate in-
crease than large customers, however, since the Commission ruled
that the rate increase should be assigned to the residential and
large general service classes in proportion to the revenue they pro-
duced in prior periods.6 2 According to the Commission:

[MIany of the uses of electric energy which create high con-
sumption are nonessential. Recognizing this, we believe that
the revised residential rates should place more of the burden
on the high-use customer.6

3

It is interesting to note that the rate design which emphasized
the "U" shape and put higher increases on the last block, and which

59. Virginia Electric & Pbwer Co., Case No. 19342 (Va. St. Corp. Comm'n.,
June 17, 1974).

60. Id. at Schedule I.
61. Id. at 8.
62. Id. at 38.
63. Id. at 39.

1975] 61



62 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

was approved by the Commission in the more recent Vepco case,
was proposed by the company. Indeed, many utilities, after first
fighting rate design which lessened quantity discounts for residen-
tial customers, now advocate them to lessen revenue erosion.

C. Consolidated Edison Company of New York

The Consolidated Edison Company of New York has itself ad-
vocated structuring rate increases so as to impose upon certain
groups of highest use customers the highest percentage increases.
A lessening of revenue erosion appeared to be the principal reason
for these proposals.6 4 As a staff witness on rate design for the New
York State Public Service Commission has testified:

Flattening rates help reduce revenue erosion due to increased
energy consumption. Increased usage per customer over a period
of time occurs in the lower priced end blocks resulting in lower
average revenues per kwh. To the extent that the Company is
experiencing increased usage per customer rather than increased
numbers of customers, growth in revenues cannot keep pace
with growth in sales which produces a continued erosion of
net earnings. Therefore, greater increases in rates should be ap-
plied to blocks experiencing or expected to experience the
greatest growth. If sales growth is not recognized, the result
is revenue erosion and a continuing need for revenue relief.
Higher usage blocks are contributing substantially to a need for
new, more costly plant.5

In the 1972 Consolidated Edison case," the Commission under-
scored the negative effect promotional aspects of stepped-down rates
have on revenues. The Commission stated that

the promotional aspect of stepped-down rates . . . is no longer
valid, at least in the case of Con Edison. Confronted with an
inability to expand capacity along economical lines, Con Edison

64. Consol. Edison Co., Case 26105, 12 N.Y.P.S.C. 630 (March 29, 1972).
65. Testimony of Cheryl Beach, Record at 2269, Consol. Edison Co., Case 26309,

13 N.Y.P.S.C. 1491 (Sept. 6, 1973). Regarding revenue erosion, see also Beach &
Saffer, Revenue Erosion and Electric Rate Increases, 90 Pun. UTiL. FORT. 34 (Dec.
7, 1972); Epstein, A Proposal to Modernize Electricity Tariffs, 92 PUB. UTIL. FORT.

24 (Aug. 30, 1973); Address by Charles F. Luce, Chairman of the Board of Con-
solidated Edison Co. of New York, before FPC 50th Anniversary Ceremony, June
30, 1970, in Brief for Citizens for Clean Air, Inc., as Intervenor, supra note 1, at
14-15.

66. Consol. Edison Co., Case 26105, 12 N.Y.P.S.C. 630.

[2: 40



Problems in Electric Utility Rate Design

is forced to meet increased loads by adding and running costly
and inefficient gas turbines which use expensive fuel at rela-
tively high heat rates; by retaining and operating an expensive
and inefficient obsolete plant; by purchasing extraordinarily
large amounts of power, at high cost, from other utilities; and
by proceeding simultaneously with a number of expensive capi-
tal additions without any knowledge as to when any of them
will become operational. It is clear that, except for load which
is clearly off-peak or offers other specific economies, the result
of the growing demand for electric power is to increase the
average cost of service. In short, the incremental cost of in-
creased volumes of electric power for many applications, and
for the system as a whole, is in excess of the average cost of
providing power to existing users: increased demands for power
lead to disproportionately large increases in cost.6 7

The following year in the 1973 Consolidated Edison case," the
Commission questioned whether overall system-wide economies of
scale exist, and held that stepped-down rates should be modified
for Con Edison since incremental costs of new capacity and energy
were exceeding average costs (i.e., new plant was being added at
higher unit costs). 69 Further, modifications in quantity discounts
were ordered on the ground that increases in demand and the
pressure to add new plant were coming primarily from increased
consumption, mostly in the last blocks in the rate structure, by
existing customers rather than from new customers. Thus, the
Commission sought to correct the situation wherein the greatest
demands were being placed on the system by customers paying the
smallest block rate. These corrections imposed upon larger use
blocks a higher percentage rate increase. This action was considered
cost-justified, since the largest users were primarily responsible
for increased growth in demand and thus responsible for the utility's
need to build new, higher-unit cost plant.

In the first step of its analysis, the Commission noted that the
demand for electric power on Con Edison's system was not at-
tributable to any increase in the number of customers served by
the company. Rather, the number of Con Edison's customers had
been steady or declining; and, the Commission found increased
demand for power, leading to increased costs and revenue erosion,

67. Id. at 654-55.
68. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491 (Sept. 6, 1973).
69. Id. at 1513, 1525-27.

631975]



64 COLUMBIA JOURNAL OF ENVIRONMENTAL LAw

was attributable to increased demand per customer.70 The second
step was to confirm this conclusion by the billing data analysis
presented to the Commission in both the 1972 and 1973 Consoli-
dated Edison cases. The breakdown presented in both cases showed
kwhr sold in each block of consumption for several major service
classifications, including residential, small commercial, and indus-
trial and commercial redistribution (i.e., master-metered office
buildings where electricity is included in tenants' rent). The largest
use blocks for SC-1, residential customers, increased 270% over the
1964-71 period while lesser use blocks had a growth of 103-143%.
Small commercial and industrial customers experienced terminal
block kwhr increases of 191% compared to 100-152% growth in
lesser use blocks.7 ' This data lent justification to the action requiring
the largest use customers to contribute more towards the construc-
tion of new plant.

The 1972 and 1973 Consolidated Edison cases were significant
for reasons other than the Commission's acceptance of the notion
that higher use blocks were responsible for increased demand on
the system. Most importantly, these were two of the earliest cases
to delve into the economic structure of the utility's system and
to determine in what manner this structure has changed. Within
virtually all service classifications, until the 1973 Consolidated
Edison case was decided, there had been substantial quantity dis-
counts for large blocks of usage. This pricing scheme had been
upheld by the Commission in prior cases, even though no cost of
service studies to break down costs by block had existed. And, as
long as the electric utility industry was experiencing annual re-
ductions in cost and, therefore, in the price of electricity, the
stepped-down rates which had been prevalent in the electric power
industry almost since its conception remained valid.

It has been generally considered that a stepped-down rate
structure with lower unit charges for higher volume consump-
tion was justified on the basis of economies involved in serv-
ing larger as against smaller customers. The larger volume of
energy consumption was thought to improve the customer's
load factor and achieve more economical use of transmission
and distribution facilities. Further, service to larger customers

70. Consol. Edison Co., Case 26105, 12 N.Y.P.S.C. at 655.
71. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at Exhibit 149.

[2: 40



Problems in Electric Utility Rate Design

was believed to result in economies of scale, since larger size
conductors, transformers and other equipment cost less per unit
of capacity than smaller facilities.72

The Commission noted that other justifications advanced for
stepped-down rates were economies associated with growth in elec-
tric power production and, if overall volume can be increased,
economies which will redound to the benefit of all the system's
customers."

However, in its initial finding that rates should be redesigned,
the Commission determined that overall system-wide economies of
scale no longer exist.7 4 The Commission held that stepped-down
rates should be modified for Con Edison since the incremental
cost of new capacity exceeds average costs." The Commission's
decision in the 1972 Consolidated Edison case imposed a higher
percentage rate increase upon larger use blocks, but noted that
justifications for stepped-down rates which reflect improved load
factor, and therefore economies in distribution and transmission,
may still exist.76 The following year, in the 1973 Consolidated
Edison case, the Commission concluded

there is no record evidence to support a finding that volume
discounts are justified on the basis of economies of scale.7 7

To further its analysis, the Commission examined the record to
determine whether improved load factors,7 8 normally associated
with volume usage, could justify a continuation of the stepped-down
rate structure; it attempted to ascertain the cost responsibility based
on load factor analysis to determine whether larger customers make
more efficient use of plant. The Commission found that in several
service classifications there is no correlation between larger users
and high load factors.79 Thus, the largest users would not utilize
plant most efficiently, since they would not tend to require elec-

72. Id. at 1525-26.
73. Id. at 1526.
74. Consol. Edison Co., Case 26105, 12 N.Y.P.S.C. at 654.
75. Id. at 655.
76. Id. at 654.
77. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1526.
78. The most desirable load factor would be that associated with a customer who

used electricity 24 hours per day.
79. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1529.

1975] 65



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

tricity around the clock; as a result, they should not be entitled
to lower quantity discount rates.

Con Edison also presented evidence as to the contribution cus-
tomers of various size made on capacity or demand responsibility.
John Monsees, Director of Con Edison's rate department, testified
in the 1973 Consolidated Edison case that the smallest customers
impose less capacity or demand responsibility per kwhr of use than
do larger customers. Coincidence factors (a measure of the tendency
to exert demand at the same time as the system's operation peak)
for classifications including most large use customers (SC-4, 8, 9)
are generally in the 70-90% range. Coincidence factors for the larger
users in the small residential customer class (SC-1), and in the
small commercial and industrial customer class (SC-2), are in the
40-60% range; for the smallest SC-1 and SC-2 customers, coinci-
dence factors fall between 25-30%." Thus the smaller use service
classifications and smaller use blocks within a given service clas-
sification tend to contribute less to peak demand than larger use
service classifications and higher use blocks within a given service
classification. Since unit costs of producing electricity increase
with added capacity, and larger users contribute most to the need
for such new capacity, the economic justification for affording
quantity discounts to large users is seriously undermined."

The Commission based its decision in the 1973 Consolidated
Edison case on information indicating that the largest users did
not make the most efficient use of existing plant, and that the
largest use customers within service classifications and the largest
use service classifications contribute most to peak demand and the
need to build new higher-unit-cost plant. The Commission ordered
the block structure of stepped-down rates to be replaced by a single
energy charge for residential customers (SC-1) and small commer-
cial and industrial customers (SC-2) .2 Other modifications to Con
Edison's stepped-down rate structure included flattening out de-
mand or capacity-related charges for multiple dwelling, sub-meter-

80. Testimony of John Monsees, Record at 3876, Consol. Edison Co., Case 26309,
13 N.Y.P.S.C. 1491 (Sept. 6, 1973).

81. Brancato, supra note 15, at 84.
82. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1528. A two-tier rate

structure was later approved, imposing a rate increase of no more than 25% on
highest use customers.

[2: 4066



Problems in Electric Utility Rate Design

ing customers (SC-8) and instituting a two-step demand charge
for larger commercial and industrial customers (SC-9)." The Coin-

83. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1531. An example of the
Commission's decision to level rates is the following:

ELECTRIC RATE

SC-2: SMALL COMMERCIAL AND INDUSTRIAL

Before Decision Case 26309 After Decision Case 26309

First 10 kwhr $2.67 min. chg. First 10 kwhr $4.00 min. chg.
Next 290 kwhr 5.5540/kwhr All over 10 kwhr 4.630/kwhr
Over 2,100 kwhr 3.6090/kwhr

(Source: Brancato, supra note 15, at 80.)

It is interesting to note that while in the 1972 Consolidated Edison case the Com-
mission made recommendations to impose higher percentage increases on higher use
blocks, in the 1973 Consolidated Edison case, the Commission chose the route of
leveling the actual rates charged in each block. The difference between the two
approaches illustrates one of the problems inherent in trying to reduce quantity dis-
counts by applying higher percentage increases to higher use blocks. The Com-
mission recognized that to apply increasingly greater percentage increases to end
blocks may not change the actual tilt of the declining block rate structure. Indeed,
depending on the mathematics involved, there may be an even wider spread between
the first and last block under the percentage increase method than would be under
equal absolute increases for each block or by leveling completely. The following
table illustrates this fact:

SC-9: HIGH TENSION DEMAND CHARGES

Rates in Con Edison's Con Edison's
effect Proposed Proposed
before % Increase Final Rates
Case in Case Absolute in Case
26309 26309 Increase 26309

First 100 kw
of maximum
demand $5.13/kw 19.8% $1.02/kw $6.15/kw

Next 200 4.08 21.3 .87 4.95
Next 9,700 3.63 21.5 .78 4.41
Next 15,000 3.33 22.2 .74 4.07
Over 25,000 2.63 25.5 .67 3.30

Difference
between first
and last
block $2.50/kw $2.85/kw

(Source: Brief for Citizens for Clean Air, Inc. as Intervenor, supra note 1, at 16.)

While the disparity for rates in effect before the 1973 Consolidated Edison case
between the first and last blocks in SC-9 is $2.50/kw, the disparity increases to

671975]



68 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

mission also noted that in future cases it would consider making

further adjustments to the rate structure of SC-9 if "the evidence
continues to indicate a lack of correlation between size and group
load factor."8 While data indicated that the rate structure for an-
other classification (the commercial redistribution classification)
should be revised to lessen quantity discounts, the Commission
held that substantial restructuring of rates in this category would
result in unduly abrupt changes.S5 Finally, the Commission found
insufficient data prevented the revision of rate structures for the
other service classifications.8 6

Perhaps the most significant decision the Commission made in
the 1973 Consolidated Edison case was to shift the burden of proof
for justifying declining block rate structures to the utility com-
panies. While the Commission did not eliminate rate differentials
which it considered to be justified by cost considerations, it warned
that in the future it will be incumbent on those advocating reten-
tion of rate differentials to demonstrate cost justification. 7 Thus,
the Commission implicitly announced its intention to move toward
rate redesign unless compelling evidence is presented to dissuade it
from so doing.

In what we may refer to as the second phase of its opinions, the
New York State Public Service Commission discussed in the 1975
Consolidated Edison case8 how the theoretical model for rate de-

$2.85/kw by applying higher percentage increases to higher use blocks. Thus, by
the order in the 1972 Consolidated Edison case to apply higher percentage increases
to higher use blocks, rates in absolute terms can be made more promotional. It was
not until the 1973 Consolidated Edison case that a true reduction in the promotional
rate structure was affected by the PSC's ordering a leveling of rates.

It is also obvious that a reduction in the tilt of declining block rates would not be
made if all blocks were to receive an equal absolute increase. For example, if in the
example above all blocks were to be increased by $:87, the declining block structure
would remain unchanged and the new rates would be:

minimum charge $6.00
next 200 kw 4.95
next 9,700 kw 4.50
next 15,000 kw 4.20
next 25,000 kw 3.50

84. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1531-32.
85. Id. at 1529.
86. Id. at 1527-32.
87. Id. at 1534-35.
88. Consol. Edison Co., Case 26538, 8 P.U.R.4th 475 (N.Y.S. Pub. Serv. Comm'n.,

April 28, 1975).

[: 40



Problems in Electric Utility Rate Design

sign must be adapted to incorporate changes in the economic struc-
ture of the industry; it determined that the whole model must be
revised to replace historic costing with incremental costing in or-
der to achieve a newer, more broadly-based concept of economic
efficiency.89

The Commission reevaluated rate design predicated on the tra-
ditional cost model, according to which cost of service studies based
on historic costs are devised and company costs are distributed on
the basis of objective assignments, apportionments and allocations
among the various classes of service. Use of historic costs was the
long-standing Commission policy, and one that the Commission
felt made obvious sense in terms of its responsibility to insure that
rates are fair, reasonable, equitable and not unduly discriminatory.
The Commission conceded that rates designed on the traditional
model served the industry and the public interest only in periods
of moderate inflation and when increases in the level of costs were
more than offset by technological progress and the achievement
of economies of scale. In its opinion, the Commission noted that
these conditions no longer prevail generally and that "rates fash-
ioned only on the traditional basis do not necessarily achieve
such closely interrelated purposes as economic efficiency, environ-
mental protection, and conservation."o The Commission set as its
goal the achievement of a rate structure based upon principles of
economic efficiency, which include requiring price to reflect exter-
nalities, such as environmental degradation, as well as those costs
explicitly borne by supplying companies. Conservation, which dis-
courages the wasteful consumption that occurs when prices are be-
low cost, is now considered a necessary component of economic
efficiency." In short, there has been a marked shift in emphasis;
a new rate structure, constructed in the interest of economic ef-
ficiency, has replaced one whose primary purpose was to effect a
fair and equitable distribution of the total revenue requirements
of a company.

The Commission's opinion in the 1975 Consolidated Edison case
points out the most important differences between the two rate
structures. First, economic efficiency will require that prices be

89. Id. at 478-81.
90. Id. at 479.
91. Id.

691975]



70 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

calculated on the basis of marginal or incremental costs. Second,
the only measure of incremental cost that is pertinent is current
or future costs; costs that have already been incurred can no longer
be avoided even if incremental units are not purchased. Third,
the value of the service component is minimized in favor of a
stricter cost basis for setting rates. In designing rates to achieve
a fair or equitable distribution of total costs, weight was given to
the respective benefits that various users or classes of users derive
from the system. Thus, such distributions and the rates that issued
from them depended not only on cost but on value of service to
the customer.9 2 But the Commission ruled, instead of the old equi-
table rates which included a value of service component, the new,
efficient rates should be based on marginal costs-not on what cus-
tomers are willing or able to pay.s However, the Commission does
advocate the use of value of service criteria to set rates when rates
based exclusively on incremental costs yield companies either in-
adequate or excessive revenues." This represents an important shift
to a more future-oriented and more precisely cost-related rate de-
sign. Defining efficiency as at least theoretically encompassing
environmental concerns and the cost to society at large of environ-
mental degradation and natural resource depletion is a major ad-
dition to rate design theory.

The Commission noted that flattening rates, allocating capacity
costs on the basis of peak responsibility, extending seasonal differen-
tials, and introducing time differentiated pricing do not provide a
complete solution to the problem of rate redesign. Nor do they nec-
essarily produce optimally efficient rates, since in certain cases they
may only approximate true incremental costs.5 Nevertheless, the
Commission considers them steps in the right direction and has
ordered steps towards their implementation. To this end, the Com-
mission has required quantity discounts to be eliminated, in most
cases, except where customers attain superior load factors with their
increased use and are, therefore, economically entitled to a reduced
rate. In addition, to further the process of implementing new rate
design techniques in New York, a new, generic rate procedure has

92. Id. at 480-81.
93. Id. at 481.
94. Id.
95. Id.

[2: 40



Problems in Electric Utility Rate Design

been initiated in which the theory and practicalities of rate design
will be considered for all utilities in the State.90

D. Detroit Edison Company

The Michigan Public Service Commission has also reevaluated
the changing technological state of the utility industry and its
ramifications on declining block rate structures. In a 1974 case in-
volving the Detroit Edison Company, the Commission stated in an
interim order:

The electric utility industry has until recently experienced a
general downward trend in the cost of producing and supplying
electric energy. The more kilowatt hours that were sold, the
less they cost. . . . Large generating plants cost less per unit
of output than did small generating plants. Technology was able
to lower costs with each passing year. Transmission and dis-
tribution facilities to move the energy from the production plants
to the customers were more fully utilized as more customers
with greater usage began to use electric energy. The unit cost
of supplying electric energy as a result dropped dramatically
over the years. "Declining price" rate structures were a natural
result of this phenomenon.97

The Commission took cognizance of the fact that the time-honored
economics pertaining to the electric utility industry had changed:

Today, things are different. Costs of building and operating
an electric system have turned around. The incremental cost of
producing the next unit is higher than the existing costs. Every
additional unit of electric energy that must be provided will in-
crease the overall cost of supplying energy.98

The Michigan Commission ruled that flatter rates for residential
customers are in the public interest. Referring to a rate structure
consisting of a monthly charge and a flat rate per kwhr, it observed
that

this form of rate structure for residential customers is realistic
in terms of the cost to the utility of supplying electric energy.
By raising the price in areas of consumption with high growth

96. Id. n.3; (this generic rate procedure is found in Consol. Edison Co., Case
26806 (N.Y.S. Pub. Serv. Comm'n.).

97. Detroit Edison Co., Case U-4257, 2 P.U.R.4th 188, 197 (Mich. Pub. Serv.
Comm'n., Sept. 12, 1973) (interim rate).

98. Id.

1975] 71



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

rates, the incremental cost of additional demand on the electric
system is more truly reflected in the revenues of the utility.99

While the Michigan Commission did not flatten residential rates
altogether, it did make what it called a "fundamental move in the
direction of 'flatter rates'";1oo rates for the low usage customer were
reduced by 3.5% to 5.7%, while the prices for the high use customer
were increased by 2.7% to 5.4%. A distinction was drawn by the
Commission between flattening rates for residential users and the
need for a rate redesign pertaining to large commercial and indus-
trial customers. No attempt was made to deviate from past rate
design for the latter customers:

Before the Commission can make changes in the structure of
the commercial and industrial rate schedules, it must have facts
to consider the impact of the changes on the economy of the
state. The Commission would not like the cost of electrical
utilities to be a disincentive to economic growth of Michigan
or to result in the loss of jobs. The Commission will conduct
special inquiries into this matter over the next year.10 '

In its final order,10 2 the Michigan Commission reiterated its
stance on rate redesign: for residential users, customers using 200
kwhr per month received an increase of 3.3%; whereas customers
using 2,000 kwhr per month received an increase of 9.2%. In addi-
tion, the residential space heating rates were increased to raise the
relative rate of return at the same time this class was changed
to correspond with the revision in the residential schedule. The
lower price applicable to over 1,000 kwhr per month on this rate
schedule was eliminated for usage during the summer season so
as to allow all residential customers with air conditioning equip-
ment to be treated alike.1 0 3

E. Madison Gas and Electric Company

The Public Service Commission of Wisconsin, in a 1974 case in-
volving the Madison Gas and Electric Company, found that a flat

99. Id. at 198.
100. Id.
101. Id. at 199.
102. Detroit Edison Co., Case U-4257, 3 P.U.R.4th 209, 249 (Mich. Pub. Serv.

Comm'n., Jan. 4, 1974) (final rate).
103. Id. at 250.

72 [2: 40



Problems in Electric Utility Rate Design

rate design is reasonable, just, and a proper means of recovering
energy and demand costs.10 4 The actual changes made in rate struc-
ture substantially increase terminal block charges throughout the
service classifications and impose in several service classifications
a different set of rates for winter than those for summer, with
summer rates having higher charges. With respect to residential
rates, the Commission determined that the record did not justify
the declining block structure proposed by the utility, and it or-
dered a flat residential rate with a winter/summer differential
amount of 0.70 per kwhr for use over 1,000 kwhr.'0o

In addition, the Commission increased the minimum charge to
more properly reflect total customer related costs. This had been
an area of controversy within the case since the environmental in-
tervenors had argued that more customer costs should be recovered
in the minimum charge rather than having only partial customer
costs so recovered and the remainder spread over the higher con-
sumption blocks. The intervenors argued that spreading customer
costs in this manner is inappropriate as a matter of economic logic
and magnifies the differential between the initial blocks and the
last block, fostering the belief that electricity is cheap when used
in large amounts.'06

The Wisconsin Commission also imposed a 33% increase on the
terminal block for the commercial classification and made adjust-
ments to shift the revenue responsibility from the energy to the
demand charges (this was in keeping with the utility's long-run in-
cremental cost study). The industrial rate classification received a
demand charge increase in the terminal block of 60%. Moreover,
a summer/winter differential was imposed for even the minimum
kw of demand because of the very substantial number of commer-
cial and industrial air conditioning customers which take service
on these schedules.1 07

In addition to substantial rate design changes, the Wisconsin
Commission, like the New York State Commission, shifted the bur-
den to the utilities to prove the justification for a declining block
rate structure.08

104. Madison Gas & Electric Co., Case 2-U-7423, 5 P.U.R.4th 28 (Wis. Pub.
Util. Comm'n., Aug. 8, 1974).

105. Id. at 40.
106. Id. at 41.
107. Id. at 40-42.
108. Id. at 39.

731975]



74 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

The 1974 Madison Gas & Electric case is also significant for its
treatment of long-run incremental costs (LRIC). The Environmen-
tal Defense Fund chose the 1974 Madison Gas & Electric case as
a test case on electric rate design. The Environmental Defense Fund
introduced evidence on the advisability and feasibility of employing
LRIC as a basis for assigning electric utility rates.09 In addition,
Dr. Irwin Stelzer, a noted economist, appeared as a witness for the
company; he too suggested that the economic principle of marginal
cost pricing be adopted and implemented in the form of rates
based on LRIC.1 o

The Commission, in its opinion, discussed LRIC, beginning with
the observation that the marginal cost of an item

refers to the change in cost that occurs with infinitesimally
small changes in output. A central proposition of economic
theory is that when prices of goods and services are set equal
to their marginal costs of production, an optimum allocation of
resources results. This occurs because the price will reflect the
cost to society of producing one more unit of the good."'

The Commission further noted that the major obstacle in applying
marginal cost pricing to electric utilities is measuring marginal
cost."2

Theoretically, the economically efficient price . . . is set at
the short-run marginal cost (SRMC) of the smallest possible
additional unit of sale. However, rather than short-run marginal
cost, long-run incremental cost has been suggested as the logical
surrogate for marginal cost. Long-run incremental cost is the in-
cremental cost of the capacity and output which can reasonably
be expected to be added in the next several years.12a

The Commission discussed two reasons for looking to LRIC rather
than SRMC. The first was practicality, since LRIC lends itself to
measurement while SRMC does not. The second, and more basic
reason, is the volatility of electric utility rates when tied to SRMC.
Rapidly fluctuating rates would result, possibly depriving consumers

109. Id. at 34.
110. Id.
111. Id.
112. Id.
113. Id.

[2: 40



Problems in Electric Utility Rate Design

of those "expectations of reasonable continuity of rates" on which
they must rely in making plans requiring the consumption of elec-
tricity.114

Madison Gas and Electric provided for the record estimates of
the utility's LRIC. The LRIC study divided costs into the three
components normally associated with fully distributed cost-of-ser-
vice studies: (1) customer costs (meter reading, billing, etc.); (2)
energy costs (that part of distribution costs which has been desig-
nated to cover operation and maintenance of existing plant, and
which varies directly with the amount of kwhr consumed); and
(3) demand costs (including generation and transmission capacity
costs that vary with total kw of demand). In the LRIC study, the
future costs of demand were estimated on the basis of anticipated
expenses (adjusted to current prices) of additions to the utility's
plant."i5

The LRIC study was accepted by the parties and the Commission.
The intervenors merely questioned specific issues relating to the
estimates of LRIC. For instance, the treatment of inflation in the
study was questioned, with several intervenors arguing that the
estimated capacity costs, construction costs, and other utility costs
should reflect expected future inflation. There was also some dis-
agreement concerning the allocation of costs between customer
and demand categories. Despite these reservations, the Commis-
sion concluded:

We believe that the appropriate bench mark for the design of
electric rates in the case is marginal cost as represented by the
practical variant, long-run incremental cost. If electric rates are
designed to promote an efficient allocation of resources, this is
a logical starting point.116

The Wisconsin Commission further noted that

[i]t must be understood that the long-run concept is pursued as
the most appropriate and the most practicable cost measure-
ment. The fact that "long-run" incremental cost is being used
does not imply that the resulting rates will be valid for a long
time into the future, nor that they will compensate for infla-

114. Id. at 34-35.
115. Id. at 35.
116. Id.

751975]



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

tionary cost increases. The primary objective that LRIC-based
rates are intended to accomplish is to guarantee an efficient
allocation of resources directed toward the production of elec-
tricity."x 7

Moreover, in a concurring opinion, the Chairman of the Commis-
sion, William F. Eich, remarked:

An electric rate design based on LRIC, then, will insure that
those users placing the greatest demands on the system will pay
the true costs of such usage-including the costs of new generat-
ing capacity. Such a design would give the proper "signals" to
customers-that the more you use, the more costly it is to you
and to society-and, to the extent that demand is elastic; it would
have a desirable dampening effect on demand growth."i8

IV. THE NEW ECONOMICS OF ELECTRIC

UTILITY RATE DESIGN

As we have seen, the regulatory commissions discussed above
have accepted, to a varying degree, the proposition that the electric
utility industry has undergone fundamental economic changes. In
response, they have ordered substantial changes in utility rate de-
sign. One of the most prominent alterations derives from the notion
that the costs which are used to determine the rates charged
customers should be based on a more future-oriented long-run in-
cremental cost system rather than on an historic, fully distributed
cost system wherein measured costs are those incurred in some
previous period.

117. Id. at 35-36.
118. Id. at 45 (concurring opinion of William Eich, Chairman).
In other proceedings, economists, including Dick Netzer of New York University,

William Vickery of Columbia University, Charles Olson of the University of Mary-
land, and Charles Cicchetti of the University of Wisconsin, have advocated pricing
for utilities based on long-run incremental costs. Professor Vickery testified in the
1975 Consolidated Edison case that the concept of marginal pricing would insure that
the cost of service is most precisely assigned to the recipients of that service. Testi-
mony of William Vickery, Record at 9702, 9710-11, Consol. Edison Co., Case 26538,
8 P.U.R.4th 475 (N.Y.S. Pub. Serv. Comm'n., April 28, 1975).

While existing cost allocation studies are based on historical customer usage data,
a marginal cost pricing system would correlate future costs of additions to plant with
customers whose additional or incremental demands are responsible for the need
to expand the plant.

76 [2: 40



Problems in Electric Utility Rate Design

Substantial changes in rate design flow from this fundamental
change in approach. For instance, the declining block nature of
rate design whereby quantity discounts are given to large users
must be reevaluated. So must the time periods during which costs
are measured; peak pricing appears more necessary, as do sea-
sonal differential rates. Finally, the allocation of costs among ser-
vice classifications and among blocks within service classifications
must be reviewed to remove existing biases towards the historical
cost approach and accommodate the more up to date economic
philosophy.

A. Long-Run Incremental Costs and Pricing Systems:
Inverted Rates, Flat Rates and Peak Pricing

In a discussion of long-run incremental costs, it is useful to
emphasize the distinction between short-run and long-run eco-
nomics in the utility industry. In the short-run, when capacity is
fixed, a pricing system which would encourage full utilization of
capacity should be encouraged in order to spread the fixed costs
over the largest possible number of users. Thus, there are so-called
economies of scale in the short run for use which can be completely
confined to off-peak times. The historic pricing system "tended
to meet the requirements of both a short-run load factor improve-
ment and long-run capacity expansion objectives.""9 Quantity dis-
counts were justified on the basis of load factor improvement or
fixed cost spreading in the short run. If the available capacity was
not surpassed, greater spreading of fixed costs would result, tending
to improve system load factors and reduce cost. However, with this
approach a conflict arises when expansion in energy consumption
occurs at the same time that expansion in peak demands occurs.12 o
When the system's peak expands and energy consumption exceeds
the available generating capacity, it becomes necessary to expand
facilities. It is the long-run expansion of facilities and the need
to build higher-cost plants, which increase average costs, that has
created the principal concern in declining block pricing systems for
electric utilities. Minimizing incremental capacity costs while, at the

119. Cicchetti, Electric Price Regulation: Critical Crossroads or New Group
Participation Sport, 94 PuB. UTL. FORT. 13, 14 (Aug. 29, 1974).

120. Id.

771975]



COLUMBIA JOURNAL OF ENVIRONMENTAL LAw

same time, improving the load factor are the dual objectives of
electricity pricing. However, the fact that newly-installed increments
in capacity are now being brought on line at significantly higher
cost per kw than historic costs causes long-run and short-run ob-
jectives of electricity pricing to conflict.1'

Several possible pricing systems could be derived using LRIC.
The first uses "inverted rates," to price higher use blocks at higher
rates than preceding blocks. The traditional quantity discount rate
structure takes the opposite approach, pricing these blocks at the
lowest rate. Where environmental intervenors in electric utility cases
have proposed inverted block pricing, it has been rejected by most
utility commissions as economically unsound. 22

A second method of basing a pricing system on LRIC would
be to institute a flat rate based upon an average of LRIC. The flat
price (i.e., a fixed flat rate per kw or kwhr) is easier to compute
and implement, and represents a smaller deviation from the past.
Some who propose flat tariffs have also suggested the adoption
of a practice called "the inverse price elasticity rule,"" 3 which
means that LRIC would be the basis of pricing in each customer's
category. If excess revenues result, prices would be reduced pro-
portionately more for those users who are least likely to expand
their consumption when confronted with the lower price. This
means the less price-elastic the demand for a customer category,
the greater the deviation between the flat price charged and the
LRIC of supplying that customer class."4

However, neither the inverted rate pricing system nor the flat
rate coupled with the inverse price elasticity system would be likely
to assign costs in the most precise manner. While both of these
pricing reforms may result in minimized capacity expansion by in-
creasing costs to the largest users and thus discouraging consump-
tion, they are both likely to detract from achieving the objective of
spreading the fixed costs and therefore of improving load factor.2'

121. Id.
122. See, e.g., Consol. Edison Co., case 26105, 12 N.Y.P.S.C. 630 (March 29,

1972); Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491 (Sept. 6, 1973);
Potomac Electric Power Co., Case 568 (Phase II), 95 P.U.R.3d 118 (D.C. Pub. Serv.
Comm'n., July 28, 1972).

123. Testimony of William Vickery, Record at 9716, Consol. Edison Co., Case
26538, 8 P.U.R.4th 475 (N.Y.S. Pub. Serv. Comm'n., April 28, 1975).

124. Cicchetti, supra note 119, at 15.
125. Id.

78 [2: 40



Problems in Electric Utility Rate Design

A third pricing system designed to take into account LRIC while
establishing cost-related charges for customers responsible for the
increased demands on the system has been proposed by Dick Netzer,
Dean of the New York University Graduate School of Public Ad-
ministration. This pricing system, which establishes differentials for
peak and off-peak use, has been endorsed by the New York State
Public Service Commission in the 1975 Consolidated Edison case.126

Dean Netzer testified before the New York Commission:

First, very modest rates of growth are in prospect for [Con
Edison's] annual electricity sales, and if the present pattern of
rates is continued and rates increase rapidly enough across-the-
board, there will be virtually no growth in residential sales at
all. Second, the system peak will continue to grow substantially,
even in the face of the rate increases in prospect, if the present
pattern of rate continues. Third, the result will be a continuous
deterioration in load factor, with the prospect of even more rapid
increases in rates across-the-board and/or financial disaster for
the Company. This dismal cycle can be broken only by substan-
tially revising the rate structure in the direction of sharply high-
er rates for peak demands. Such rates can help moderate the
growth in peak demand, which can be accommodated only at
sharply increasing costs per unit of service, and in any event
will help recoup those costs, which should not fall on customers
whose demand is not contributing to rising costs of service.127

For this reason, Netzer, stressing the crucial importance of imple-
menting a more precise measurement of the use of power, urged
that peak pricing with time-of-day metering be implemented within
the Con Edison service territory. He further recommended that,
while the company is changing to time-of-day meters, the Com-
mission develop interim peak pricing rate revisions utilizing ex-
isting meters, including more comprehensive and more marked
summer differentials.12 8

Use of peak pricing and time-of-day metering has several major
advantages.'29 In the first place, it is a pricing system which makes
possible a more precise measuring of consumption, which will en-

126. Consol. Edison Co., Case 26538, 8 P.U.R.4th at 512-13. See text accom-
panying notes 88-96, supra.

127. Testimony of Dick Netzer, Record at 9916-17, Consol. Edison Co., Case
26538, 8 P.U.R.4th 475 (N.Y.S. Pub. Serv. Comm'n., April 28, 1975).

128. Id. at 9917.
129. Testimony of Dick Netzer, supra note 127, at 9916-18; Testimony of William

Vickery, supra note 123, at 9704, 9710-12.

1975] 79



80 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

able a more efficient allocation of resources.13 0 In addition, a more
accurate method of pricing will allow more accurate estimates as
to which classes of customers place the highest demand on the
system. This information in turn will facilitate more accurate pro-
jections as to how consumption patterns can be expected to change
and develop among those classes and blocks over time. The New
York State Public Service Commission, by its adoption of the ex-
isting summer and winter rate differential, and Con Edison, by its
proposal to implement a demand ratchet1"' have indicated ac-
ceptance of the basic need for more precise measurement of elec-
tricity use.

A second advantage of peak pricing and time-of-day metering is
that it will enable the company to respond, and even to some de-
gree to control, emergencies and peak conditions. Con Edison now
can only appeal to its customers to cut usage during emergencies.
The imposition of a greatly increased price for continued use dur-
ing emergencies would be an incentive toward reduction of such
use.132

A third advantage could be a direct cost savings to the company
in the form of fewer manual meter readings, since the new meters
could be read by computer and existing meters might well be
utilized as part of the operating machinery.

The final and perhaps most important advantage of peak pric-
ing and time-of-day metering would be potential reduction in the
need for the company to purchase and construct more expensive,
environmentally degrading additions to plant in order to service
peak needs.13 3

130. Testimony of William Vickery, supra note 123, at 9709-10.
131. See text accompanying notes 145-52 infra.
132. Testimony of William Vickery, supra note 123, at 9731-32.
133. Id. at 9729-32. According to the Federal Energy Administration, effective

load management could reduce by one-third the 1985 industry-projected need for
new plant capacity. The FEA's Office of Utilities Policy Development and Con-
servation Demonstration has six demand management programs underway with state
and local agencies, including the Arizona Fuel and Energy Office which has a
program for lower off-peak residential rates. The Arkansas Public Service Commis-
sion is monitoring load data for all classifications, including industrial customers, in
response to new flattened rates, increases in summer/winter differentials and time-
of-day pricing. Similar studies are being conducted by the Los Angeles Department
of Water and Power, the Connecticut Public Utilities Commission, the New Jersey
State Energy Office, the Central Vermont Public Service Co., the Green Mountain

[2: 40



Problems in Electric Utility Rate Design

With respect to the technical feasibility of time-of-day metering,
testimony in the 1975 Consolidated Edison case indicated that
fairly modern methods of time-of-day metering are in use in New
Zealand, and have been in use in Europe for many years."' For
example, in 1957, Electricit6 de France, the nationalized French
utility, adopted its "green tariff," which was basically an industrial
rate with charges bearing on the time of day and the season of
the year.'3 5 "The rate levels were based on marginal costs, and
when the tariff went into effect the utility estimated that it would
result in a 5% reduction in use of electricity at peak. The projec-
tions were met, and in 1965 the concept was extended to residen-
tial rate classifications."'

The testimony indicated that the principal application of time-
of-day metering for the immediate future should be for larger cus-
tomers, rather than in the domestic market. Studies indicated that
for certain large customers who now have recording demand me-
ters, time-of-day metering could be implemented within a very
short time period.'3 7 It was suggested that a system of voluntary
time-of-day demand metering whereby a higher peak rate would

Power Company in Vermont and the Public Utility Commission of Ohio. N.Y. Times,
Aug. 10, 1975, § 3, at 11. See also Bray, Rate Test Affects Vermonters' Habits;
Formula Could Reduce Woes of Utilities, Wall Street J., April 1, 1975, at 38.

134. Testimony of William Vickery, supra note 123, at 9712-13. In France,
customers have, in essence, a two-part rate in that the customer actually purchases
a particular ampere load. For this load the customer pays a flat monthly charge. In
addition, there is an energy charge for all consumption taken during the month; to
control the amount of load which the customer actually takes, there is a circuit
breaker set at the prescribed amount requested by the customer. This is, in effect,
a load-limiting device, and there are administrative problems associated with it. The
energy charged to the customer is the same whether he takes on-peak or off-peak
use. Testimony of Gerald R. Browne, Record at 21-22, Massachusetts Electric Co.,
D.P.U. 18072 (Mass. Dep't Pub. Util., Sept. 1974). Browne also discussed a form
of metering, which basically charges different rates for day and night use, and
studies done in England with reference to domestic peak/off-peak pricing studies.
Id. at 22-23.

135. Epstein, supra note 65, at 28-29. See also note 134 supra.
136. Madison Gas & Electric Co., Case 2-U-7423, 5 P.U.R.4th 28, 48 (Wis.

Pub. Serv. Comm'n., Aug. 8, 1974) (concurring opinion of William Eich, Chair-
man). See also Clemens, Marginal Cost Pricing: A Comparison of French and
American Industrial Power Rates, 40 LAND EcoN. 389, 391 (1964); P. CALLE,

Marginal Cost Pricing and Random Future as Applied to the Tariff for Electrical
Energy by the Electriciti de France, in ESSAYS ON PUBLIc UTILITY PRICING AND

REGULATION 99 (1971).
137. Testimony of William Vickery, supra note 123, at 9760, 9814-15.

1975] 81



82 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW [2: 40

apply (customer use would be assumed to be on peak) unless a
customer chose to install a peak/off-peak meter, in which case he
would pay a set of rates established by the Commission which
would, presumably, be lower by virtue of his having some off-peak
use."'s In this manner a phasing in of new meters could be ac-
complished with relative ease.

Even though present technology for such a meter is limited, utility
companies' demand for them would create an incentive for their
development. Technology could certainly respond to the possibility
of a new, large market for these meters. At the present time experi-
ments are being planned by the Philadelphia Electric Company
based upon modification of existing meters, so as to introduce a
time-of-day factor.3"

The Public Service Commission of Wisconsin, in the 1974 Madi-
son Gas & Electric case, took the following stand with respect to
the development and cost of time-of-day meters:

The cost associated with the installation and use of the equip-
ment necessary to implement time-of-day metering is not known,
nor was any evidence submitted on this point. Whether the im-

138. Id.
139. Id. at 9796-99. In response to interrogatories by the Environmental Defense

Fund in June, 1974, a representative of Philadelphia Electric Company described
the company's Automatic Meter Reading (AMR) research study. A pilot installa-
tion involving about 5,000 customers was scheduled for 1974 or early 1975. The
system planned by the company would permit not only the reading of residential
and commercial meters from a central point, but would have the added advantage
of permitting the company, by sending appropriate signals, to disconnect loads such
as water heaters, air conditioning compressors, and other contributors to peak loads.
This would be done only by pre-arrangement with customers, possibly through rate
differentials. This system would also permit the company to continuously monitor
local voltage conditions, switch positions and transformer temperatures. In addition,
the system could be shared with local water companies and gas companies. The
total 1974 estimated cost of the project was slightly in excess of $1,600,000 for the
cost of the 5,000 unit pilot. At that time, Philadelphia Electric expected that a
substantial percentage of this amount would be shared by other utilities.

According to the interrogatories, the total anticipated cost of the AMR among all
the company's residential customers is about $60,000,000. The company was asked
the estimated realized savings per residential customer and per total cost of residen-
tial customers for each of the five years following the completion of installation.
The response was that assuming a 7.5% inflation rate, the annual cost per meter of
manual meter reading would be about $4.67 in 1978 ($3.50 per meter in 1974).
Based on a financing charge of about 16%, this expense would justify capital in-
vestment of about $29 per customer or a total of $29,000,000. The company said
the economic justification for installing the system, assuming its operational worth
is established, will be dependent upon the value to the company of the additional
benefits of load control and distribution system monitors.



Problems in Electric Utility Rate Design

provement in system-load factor warrants any additional outlay
for metering depends on the elasticity of demand at various
times of day. However, the recording-type metering equipment
already in use for many commercial and industrial customers
lends itself to time-of-day metering at a negligible cost. In this
area an investigation into the possible benefits of such a pric-
ing system should begin without delay. Such a pricing system
could result in lower costs to the large users as well as an im-
proved system-load factor for the utility.

The Applicant will be ordered herein to investigate the feas-
ibility of such a pricing system. Since the results of such a
study could have an important impact on all electric utilities
in Wisconsin, we deem it desirable for several of the large pri-
vate electric utilities to cooperate in such a study.1 4 0

B. Summer/Winter Rate Differentials

The process of determining how to distribute costs more fairly
requires distinguishing between service not only on the basis of
volume of electricity purchased but also on the times during the
day and the year when electricity is used. Under this approach,
customers are billed separately for day and night use and for sum-
mer and winter use. Customers would enjoy lower rates during
off-peak periods; customers who confine their usage to off-peak
times (regardless of the block which they fall into by virtue of
the overall consumption) should pay less for their usage than those
responsible for extra demands at peak times.141

As discussed above,14 2 peak pricing has been used in Europe not
only to determine daily peak and off-peak usage, but also to de-
termine seasonal peak and off-peak usage. However, American utili-
ty companies have generally claimed that metering specified to
charge differentially by the time of day would be inordinately
expensive to install. In the absence of such metering, the principal
way to refine allocation is to charge differentially for summer and
winter use.

The New York State Public Service Commission approved sum-
mer/winter rate differentials in the 1973 Long Island Lighting Co.
case.14 The summer surcharge was deemed a necessary step toward

140. Madison Gas & Electric Co., Case 2-U-7423, 5 P.U.R.4th 28, 36-37 (Wis.
Pub. Serv. Comm'n., Aug. 8, 1974).

141. Brancato, supra note 15, at 86.
142. See notes 134-35 and accompanying text supra.
143. Long Island Lighting Co., Cases 26283, 26284, 13 N.Y.P.S.C. 846 (May

19, 1973).

1975] 83



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

requiring customers using air conditioners to bear a higher portion
of the costs their uneven demands placed upon the non-air-condi-
tioning customers of this "summer peaking" company.14 4 The Com-
mission held that a summer/winter rate differential for summer
peaking companies is desirable as a rate design concept, and has
since extended its usage to other companies, such as Con Edison.4 5

In the 1973 Consolidated Edison case,'4 6 Con Edison presented
evidence that in 1958 it had shifted from a winter peaking to a
summer peaking company due to an extraordinary growth in air-
conditioning demand. The summer peak had risen from 5,710 MW
in 1965 to 7,872 MW in 1972.'14 Furthermore, the gap between
the summer and winter peak demand had been increasing.14 8 Argu-
ments were made during the case that increased summer demand
created the need to build new and higher-cost additions to plant.
The widening gap between summer and winter peaks was reducing
the overall system-wide efficiency and increasing average annual
operating costs.1 4

1 Moreover, testimony indicated that summer use
imposed higher generation and transmission costs because equip-
ment is less efficient in the summer. Hot summer days increase
the need to cool steam generators, transformers and cables, and
gas turbine capacity diminishes by about 20% in the summer.'

In its decision in the 1973 Consolidated Edison case, the New
York Commission noted that the Con Edison billing system was in-
efficient, and that it could not cope with the administrative com-
plexities of a special summer rate for customer categories with a
large number of individual users. Therefore, the Commission, while
recognizing that summer/winter differentials would be effective
rate design tools for Con Edison, ordered that a summer/winter
differential be applied in the amount of $.60 per kw only to a
service classification in which there was a small number of cus-
tomers. The Commission also stated that it would consider extend-

144. Id. at 860-61.
145. E.g., Consol. Edison Co., Case 26538, 8 P.U.R.4th 475, 489 (N.Y.S. Pub.

Serv. Comm'n., April 28, 1975).
146. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491 (N.Y.S. Pub. Serv.

Comm'n., Sept. 6, 1973).
147. Testimony of John Monsees, supra note 80, at 706-07.
148. Id. at 3882.
149. Brancato, supra note 15, at 87; Testimony of Cheryl Beach, supra note 65, at

2262.
150. Testimony of John Monsees, supra note 80, at 3873.

84 [2: 40



Problems in Electric Utility Rate Design

ing seasonal rates to other classifications."1' Indeed, in the 1975
Consolidated Edison case' 2 Con Edison requested and the Commis-
sion approved significantly more widespread use of seasonal rate
differentials in the residential classification, in the small commer-
cial classification and in the residential space heating classification,
contingent upon the company's ability to overcome problems in
billing.15

3

Electric companies in other jurisdictions have also made use of
the summer/winter differential to improve the system load factor.
Missouri, for example, has had summer/winter rate differentials
since the late 1950's.154 The North Carolina Utilities Commission
approved the use of summer/winter differentials for one company
in 1971, noting that they were just and reasonable, and that "more
than twenty electric utilities operating in other parts of the nation
have rate schedules that incorporate seasonal differentials.""' The
District of Columbia Public Service Commission approved a sea-
sonal differential in 1970, saying:

The record in this proceeding demonstrates that the Company
must have additional revenue to meet the financial require-
ments imposed by the growth in demand being experienced by
the Company and its consequent necessity for increased capaci-
ty. The increase in capacity is substantially related to the
growth in peak demand. This peak occurs in the summer period
and unquestionably is related to the heavy use of air condition-
ing in Pepco's [Potomac Electric Power Co.] service area. We
believe that the added costs involved in meeting this peak de-
mand can legitimately be recognized by the charging of higher
rates for higher levels of summer usage.'56

The Public Service Commission of Wisconsin has dealt with peak
load pricing, stating that a fully implemented application of LRIC
pricing would have to be reflected in price differentials for on-

151. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1522-24. The service
classification was that for multiple dwellings in which electric charges are included
in tenants' rents (SC-8).

152. Consol. Edison Co., Case 26538, 8 P.U.R.4th 475.
153. Id. at 494-95, 501-03, 506.
154. Union Electric Co., Case 17433 at 12 (Mo. Pub. Serv. Comm'n., Nov. 17,

1972).
155. Virginia Electric & Power Co., Case E-22, 88 P.U.R.3d 261, 265 (N.C.

Util. Comm'n., April 29, 1971).
156. Potomac Electric Power Co., Case 541, 84 P.U.R.3d 250, 254 (D.C. Pub.

Serv. Comm'n., June 29, 1970).

1975] 85



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

and off-peak sales.5 7 The Commission stated that a first approxi-
mation to such peak load pricing is the summer/winter differential
which had been proposed by the Madison Gas and Electric Co. This
differential was deemed to reflect the costs of a seasonably peaking
electric utility better than a year round rate. The Wisconsin Com-
mission stated, however, that full peak load pricing applied to elec-
tric rates must take the form of time-of-day metering.

Under such a plan, rates would vary with the time of day in or-
der to reflect the true cost of peak demand. Customers are com-
pelled to pay for the actual cost they are imposing on society and
are rewarded for shifting consumption to an off-peak time, there-
by improving the utility's load factor. The winter/summer dif-
ferential does not offer such an alternative. Summer air-condi-
tioning cannot be postponed until winter.158

C. Denwnd Ratchets

A demand ratchet is a form of rate design whereby customers
are billed throughout the year on the basis of their maximum annual
demand or their maximum demands during the peak capacity sea-
son. A customer pays a rate for his maximum peak demand and
then is charged a monthly demand rate which is a fixed percentage
of his annual or seasonal peak demand. If the original peak is ex-
ceeded, that new peak becomes the basis for charging the customer.

It has been argued that demand ratchets more fairly charge cus-
tomers for their share of the company's generation and distribution
costs and tend to reduce customers' demand fluctuations. As one
authority has testified:

Ratchets force customers to pay some portion of the fixed costs
on plant required to meet peak demands whether or not a cus-
tomer uses his peak demand all year round. In effect, ratchets
increase demand charges to customers whose demands vary ex-
tensively from month to month . . . . The Company must pay
interest on money borrowed and the depreciation expense for
plant needed to meet peak demands. Interest and depreciation
are annual expenses to be paid whether or not the plant is
used.159

157. Madison Gas & Electric Co., Case 2-U-7423, 5 P.U.R.4th 28, 36 (Wis.
Pub. Serv. Comm'n., Aug. 8, 1974).

158. Id.
159. Testimony of Cheryl Beach, supra note 65, at 2277.

86 [: 40



Problems in Electric Utility Rate Design

Proponents for demand ratchets claim that a customer's contri-
bution to generation and transmission costs is most nearly approxi-
mated by his maximum annual demand. Five major New York State
utilities (Central Hudson, Long Island Lighting, New York State
Gas and Electric, Niagara Mohawk, and Orange and Rockland)
make general use of demand ratchets.1 Oo The Commonwealth of
Virginia State Corporation Commission approved a 90% ratchet for
Virginia Electric and Power Co. in July, 1974.' The Commission
found that the Company had shown that the impact of summer
peak loads determines the capital investment required to meet off-
peak demands, that these facilities can then be used in off-peak
periods without further investment, and that the ratchet clause
permitted the Company to recover higher costs associated with
providing service to those customers with a summer peak.162

In the 1973 Consolidated Edison case,'0 3 the New York Com-
mission found that it had not been established that demand ratchets
were either a feasible or desirable rate design technique for Con
Edison, but ordered studies to be performed and presented in the
company's next rate case.'6 4

The next case was the 1975 Consolidated Edison case discussed
previously.1 5 Here Con Edison presented a demand ratchet study.
On the basis of that study, it advocated a 100% summer demand
ratchet in the commercial redistribution (SC-4), multiple dwelling
space heating (SC-12), and large commercial and industrial (SC-9)
classifications. Con Edison testified: "[d]emand costs are more near-
ly annual rather than monthly costs since they are essentially the
carrying charges on plant installed to meet the maximum demands
of the customers on the various portions of the electrical system."
Monthly demands were not reputed to be a good measure of cus-
tomers' cost contribution since customers may "escape being charged
for some of the demand costs which they create," and especially

160. Id. at 3445.
161. Virginia Electric & Power Co., Case No. 19342 (Va. St. Corp. Comm'n.,

June 17, 1974).
162. Id. at 39-40.
163. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491. See text accompanying

notes 66-87 supra.
164. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491.
165. Consol. Edison Co., Case 26538, 8 P.U.R.4th 475. See text accompanying

notes 88-96 supra.

1975] 87



88 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

"if a customer's greatest monthly maximum demand is coincident
with the system peak demand."160

Con Edison's proposal would have established a pricing scheme
according to which customers would pay demand charges every
month equal to the highest summer demand charges, regardless
of when during the day their actual peak demands occurred. Con
Edison's demand ratchet proposal was opposed by the Attorney
General of the State of New York on the basis that the use of
demand ratchets would only approximate the peak contribution
that customers make to the system, and would be less precise cal-
culations than time-of-day metering. For example, should a cus-
tomer's maximum demand actually occur in a summer off-peak
period, billing throughout the year would assume that his demand
was on-peak. Furthermore, there would be no direct incentive to
reduce maximum demands at the system peak, but only an incentive
to reduce individual maximum demands, regardless of when they
occur."' The Commission recognized the disadvantage of institut-
ing a demand ratchet as compared to the more precise peak pricing
method, but ruled that a ratchet would represent a desirable inter-
mediate step and would be preferable to the present structure.
However, more study was considered necessary before implemen-
tation.168

D. Allocation of Costs Among Service Classifications

Another important aspect of recent changes in rate structure con-
cerns the manner in which the overall revenue increase is distrib-
uted among service classifications. Most utilities have relied on
general economic judgments with respect to the allocation of rev-
enues among service classifications. It is only recently that cost of
service studies have been employed in a precise manner to justify
which rate classes should receive a greater or lesser percentage of
any rate increase.

For example, the New York State Public Service Commission, in

166. Testimony of John Monsees, Record at 9295, Consol. Edison Co., Case
26538, 8 P.U.R.4th 475 (N.Y.S. Pub. Serv. Comm'n., April 28, 1975).

167. Testimony of Dick Netzer, supra note 127, at 9928-29; Testimony of William
Vickery, supra note 123, at 9704, 9727-29; Testimony of Carolyn Brancato, Record
at 10129-30, 10151, Consol. Edison Co., Case 26538, 8 P.U.R.4th 475 (N.Y.S. Pub.
Serv. Comm'n., April 28, 1975).

168. Consol. Edison Co., Case 26538, 8 P.U.R.4th at 498-99.

[2: 40



Problems in Electric Utility Rate Design

the 1972 Consolidated Edison case,6 9 approved an increase in rev-
enues applied among service classifications in such a way that each
class received about the same percentage increase; this had the ef-
fect of keeping unaltered the relationship between the service clas-
sifications. However, in the 1973 Consolidated Edison case,1 7 0 the
Commission scrutinized the basic relationships between classifica-
tions. Con Edison and the Commission staff presented cost of service
studies which apportioned the three principal types of costs-energy
costs, demand costs, and customer costs-among service classifi-
cations.17 1

Two areas of controversy have arisen concerning rate-making
practices and cost of service studies. The first is the question of how
valuable the cost of service study is in determining rates for indi-
vidual service classifications; the second questions the proper meth-
od of allocating costs among service classifications.

1. Proper Use of Service Classifications to Determine Rates. A
major controversy surrounding the use of cost of service studies
involves the extent to which they can be used to determine revenue
requirements. Testifying as an expert witness on behalf of New
York City in the 1973 Consolidated Edison case,'7 2 Professor Charles
Olson stated that the revenue requirement should be apportioned
to service classifications such that each service classification would

169. Consol. Edison Co., Case 26105, 12 N.Y.P.S.C. 630.
170. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491.
171. See text accompanying note 3 supra for a discussion of the three principal

types of costs. In Con Edison's fully-distributed cost study, which was an apportion-
ment of costs for a specific, prior time period, the method used to apportion costs
took 1970 data and assigned production and transmission costs on the basis of a
combination of (1) class demands at the time of the system peak and (2) peak
demands of the various classes whenever they occurred (non-coincident class de-
mands). Con Edison's study sampled load patterns for service classifications to
determine the contribution to the system's peak; it utilized the average four hour
demand at the time of the summer system peak-between 1 and 5 P.M. in August
1970. Data for five hot summer days were employed to arrive at the average. Consol.
Edison Co., Case 26309, 13 N.Y.P.S.C. 1491, 1514. Costs pertaining to distribution
facilities were allocated on the basis of non-coincident class demands. The staff of
the Public Service Commission updated the company's study, and adjusted it for
known changes so as to base the study upon the twelve months ending March 31,
1972. Id. at 1514-15. A new cost of service study based on 1972 data was sub-
mitted by Con Edison in the 1975 Consolidated Edison case. Consol. Edison Co.,
Case 26538, 8 P.U.R.4th 475.

172. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. 1491.

1975] 89



90 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

earn a rate of return on the investment allocated to it, equal to
the overall company-wide rate of return.1 3 Under the company's
average method of cost allocation, residential and religious cus-
tomers were paying rates which earned a 6.24% rate of return com-
pared to an overall rate of return of 6.41% based on 1970 data. The
Commission's updating of the company's average method indicated
that residential and religious customers were paying a 7.06% rate
of return, slightly less than the company overall average rate of
return of 7.16%. General small commercial and industrial customers
were found to be paying in excess of 2% over the average rate of
return; whereas larger commercial and industrial customers were
paying rates which led to a significantly lower rate of return than
the company average rate of return.17 1

The Commission upheld the principle that the rate increase should
be apportioned among the service classifications to achieve a rate
of return for each classification equal to the average rate of return
for the utility company. To this end a tolerance of plus or minus
10% of the average rate of return would be permitted as a range
within which a rate of return for a customer category would be
considered average. The Commission apportioned a rate increase
consistent with this ruling so that a larger percentage of the rate
increase was imposed on the large commercial and industrial cus-
tomers who had been returning a rate significantly below the over-
all company-wide rate of return. Furthermore, an increase smaller
than that proposed was granted to residential and religious cus-
tomers on the theory that they were already returning close to
the company's average rate.'75 The Commission's decision in the

173. Testimony of Charles Olson, Record at 3354-55, Consol. Edison Co., Case
26309, 13 N.Y.P.S.C. 1491 (Sept. 6, 1973). To arrive at a rate of return by service
classification, the following calculation is made: from revenues which are derived
by customer sales in a particular service classification, expenses for distribution,
transmission and production, are deducted according to Commission-approved
methods. This yields a rate of return by service classification which may be paralleled
to that earned by taking total company-wide revenues and deducting various produc-
tion, transmission and distribution expenses to arrive at an overall company rate of
return.

174. With the company's average method, commercial and industrial customers
were yielding a 1.64% rate of return compared to the overall average of 6.14%. With
the Commission's updated method, these customers were yielding a 4.37% rate of
return compared to a 7.16% rate of return. Consol. Edison Co., Case 26309, 13
N.Y.P.S.C. at 1517; Brief for Citizens for Clean Air, Inc., as Intervenor, supra note
1, at 31.

175. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1518.

[2: 40



Problems in Electric Utility Rate Design

1973 Consolidated Edison case marked the first time that the Com-
mission had set a tolerance range outside of which rates of return
by service classifications could not significantly deviate. This range,
moreover, was upheld against challenges to widen it to 20% made
in the subsequent 1975 Consolidated Edison case. 17

2. Methods of Allocating Costs Among Service Classifications.
Until the 1975 Consolidated Edison case was decided, Con Edison
employed in its cost of service study an allocation method which
averaged equally the class demands at the time of the system peak
with the non-coincident class demands. In the immediately pre-
ceding case, the 1973 Consolidated Edison case, the Commission
concurred with the allocation method advanced by Con Edison;
but some intervenors challenged the method of allocating produc-
tion and transmission costs. Commissioner Jones, in a dissenting
opinion, developed a cost of service study which allocated pro-
duction and transmission costs only on the basis of class demand
at the time of the summer peak (the so-called "peak responsibility"
method). Jones allocated investment and expenses for the distribu-
tion system on the basis of non-coincident class demands.177 The
issue was temporarily resolved by the Commission's decision in that
case recognizing Con Edison's own allocation method and rejecting
the peak responsibility method.1 7s The substance of the controversy
revolved around the issue of whether customer costs for production
and transmission should be those which occur only at the time of
the system's peak, or whether some measure of off-peak use should
be included. In rejecting the peak responsibility method in the
1973 Consolidated Edison case, the Commission noted that such
a method ignores demands at times other than the system's peak;
all customers use capacity, but under the peak responsibility meth-
od, the value of such capacity to some customers is ignored and
those clients are assigned little of the costs of generation and trans-
mission. Furthermore, the peak responsibility method does not take
into account the burden of off-peak use in the fall, winter, and
spring, which restricts the company's opportunity to undertake

176. Consol. Edison Co., Case 26538, 8 P.U.R.4th at 493-94.
177. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1516, Appendix B; id. at

1539-40 (concurring opinion of Commissioner Jones).
178. Consol. Edison Co., Case 26309, 13 N.Y.P.S.C. at 1516-17.

1975] 91



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

repair and maintenance work. In addition, the Commission noted
that the facilities needed to meet the system's peak in 1973 would
be utilized within one or two years to meet growing off-peak de-
mands. Therefore, electricity demands at the time of the system's
peak should not carry the entire cost responsibility for generation
and transmission facilities. The Commission ruled that the appro-
priate method for allocation of production and transmission costs
is the averaging of the summer peak and non-coincident class
demands.17 )

Intervenors in the 1975 Consolidated Edison case argued for a
peak responsibility allocation method for production and transmis-
sion costs, and the Commission decided this method was the most
appropriate.'s The rationale behind this decision was found in
testimony given by witnesses for the State of New York. Con Edison
is recognized as a summer-peaking company, which is to say that
the maximum demand exerted on the system takes place in the
summer and that the construction and maintenance programs must
be designed to meet this particular demand, since electricity cannot
be stored. It is therefore reasonable to charge customers in accord-
ance only with the demand they exert at this peak period, since
it is that period which is determinant of capacity requirements.
In a situation where a utility has a summer peak and the differ-
ential between summer and winter peaks is increasing, as with
Con Edison,'' the system becomes increasingly less efficient in
its overall utilization of plant.

Furthermore, the effects of conservation of energy, which in the
Con Edison system were found to be reducing off-peak demand
to a greater extent than peak demand, exacerbate the problem of
inefficient plant utilization. For these reasons, the argument was
advanced that cost should be assigned in accordance only with
peak demand on the system and not on the basis of an average
peak and off-peak method. Indeed, convinced of the need to assign
more costs to the peak method, the Public Service Commission's
staff witness testified that a two-thirds peak responsibility, one-
third non-coincident demand combination would be appropriate for
allocating production and transmission costs.182

179. Id.
180. Consol. Edison Co., Case 26538, 8 P.U.R.4th at 489.
181. Testimony of John Monsees, supra note 80, at 3882.
182. Consol. Edison Co., Case 26538, 8 P.U.R.4th at 483.

92 [2: 40



1975] Problems in Electric Utility Rate Design 93

It was testified by one witness in the 1975 Consolidated Edison
case that recalculated, on a peak responsibility method basis, rates
of return for residential customers are higher than shown in the
company's cost of service study, and rates of return for commercial
and industrial customers are lower. Thus, were the peak allocation
method to be used to allocate production and transmission costs,
residential service classifications would receive less of a rate in-
crease than would larger-use service classifications.'

E. Allocation of Costs Among Blocks Within
A Service Classification

Con Edison, in the 1975 Consolidated Edison case, developed a
cost of service study which allocates costs to customers according
to usage within a given service classification." As with the allo-
cation of costs among the service classifications, the company used
an average of peak and non-coincident demand to allocate produc-
tion and transmission costs to blocks of users within the service clas-
sifications. Intervenors' expert witnesses testified that this allocation
method is equally inappropriate when applied to blocks of use,
since a peak responsibility method would be more cost-related. A
reallocation based on the peak demand would-at least in the resi-

183. This is because, while residential customers contribute 23.5% to the system
peak, they are allocated a larger share, 26.4% of generation of transmission costs,
under the average allocation method. While residential customers are, under the
company's method, paying more than a cost-related share of demand costs, com-
mercial and industrial customers are paying less than their appropriate share. Com-
mercial master-metered redistribution customers were shown to be responsible for
17.3% of the system's peak, yet under the company's average allocation method, they
are accorded only 16.0% of generation and transmission costs. Larger commercial and
industrial users contribute 38.1% to the system's peak demand, yet they pay only
35.2% of generation and transmission costs. See Testimony of Dick Netzer, supra
note 127, at 9928-29; Testimony of Carolyn Brancato, supra note 167, at 10129-30.

184. The company's cost study of volume usage by groups within classes
separated costs into demand, energy, and customer components. The customer
groups were determined on the basis of annual billed kwhr and load factor.
Class demand costs were allocated to these groups on the basis of the average
of customer group coincident demand at the time of the class peak and at
the time of system peak. The required revenue for the demand component for
each class was spread among the groups in proportion to the averages of the
group coincident demand at the summer class peak and at the time of the
system peak. Then, a demand cost responsibility per kw or kwhr for each
group was determined.

Consol. Edison Co., Case 26538, 8 P.U.R.4th at 500.



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

dential classification-shift a higher percentage of the cost to higher-
use blocks than the company's allocation method, since these higher
use blocks tend to have more on-peak consumption.'" The Com-
mission agreed that it would be preferable to have used the summer
peak responsibility method to determine costs.'

Based on the company's studies, with certain reservations noted
by the Commission, the Commission ruled that there is no justi-
fication for volume discounts, as such, in the rate classes. The
Commission directed that all consumption by SC-1 residential cus-
tomers be priced at a single rate beyond the 10 kwhr included in
the minimum charge. Certain other customers in other classes do
enjoy good load factors, and it costs the company less per unit
of consumption to serve them. Rate differentials were retained
only when they were determined to be cost justified.'8 7

Religious institutions, which were included in SC-1, were de-
termined to have good load factors. Accordingly, the Commission
ordered the company to establish a separate subclassification in
SC-1 for these customers and to charge them a lower rate for use
over 1,500 kwhr. A special lower rate for water heating customers
was eliminated, and the company was ordered to price water
heating block rates to fully recover the revenue deficiency found.'18

Small commercial and industrial customers served in SC-2 evidenced
good load characteristics and relative non-coincidence of their de-
mands with the system's peak. A price differential for usage over
900 kwhr was considered cost-justified, and the flat rate was re-
placed by a two-step block rate."' In SC-4, the commercial and

185. Testimony of William Vickery, supra note 127, at 9725-27; Testimony of
Carolyn Brancato, supra note 167, at 10197.

186. In comparing the results which might have been achieved using the peak
responsibility basis for assigning demand costs on the one hand, and an average of
system and class peaks on the other, no systematic differences emerge.

For SC No. 1, it appears that additional demand costs would be assigned to

the higher use blocks under a peak responsibility basis than under the average
basis, but, for the other classes observed, SC Nos. 2, 4, and 9, slightly lower

demand costs are indicated for the higher use customers under a peak re-
sponsibility analysis. . . . [T]he company's study . . . , although not com-
pletely consistent with our decision to use a summer peak responsibility basis
for allocating production and transmission costs, nevertheless provide a useful
guide for analyzing the cost of serving customers within the classifications.

Consol. Edison Co., Case 26538, 8 P.U.R.4th at 501.
187. Id.
188. Id. at 501-02.
189. Id. at 502-03.

94 [2: 40



Problems in Electric Utility Rate Design

industrial redistribution category, the six declining-rate energy block
structure was reduced to only three declining blocks. The five
declining-rate demand blocks were replaced by three declining-rate
blocks."'o In SC-9, the large commercial and industrial class, the
two declining-rate demand blocks were retained and the blocks for
energy charges were reduced from six to two.'9 '

F. Fuel Adjustment Charges

As fuel costs become a more significant proportion of customers'
bills, the method for recovering them should be more closely scru-
tinized. In so doing, two trends must be kept in mind. First, the
fuel costs for the nuclear base load units are projected, and in many
cases have proved, to be lower than fuel costs for the fossil-fuel
and older peaking units.192 Second, variations in loads on the sys-
tem necessitate operating the least efficient, less fuel-conserving
units at peak periods. With base load plants tending to operate
off-peak' and all units, including the least efficient ones, operating
during peak periods, it may be more cost-related to replace the
flat fuel rider with a differential-peak (higher priced) and off-peak
(lower priced) fuel rider.

Proposals to roll more basic fuel costs into base rates have sur-
faced. The hearing examiner in the 1975 Consolidated Edison case
made this suggestion, as did Con Edison in its currently pending
rate case."' As fuel costs are converted into base rate charges,
their rate design takes the shape of that for base rates. Ultimately
this may lead to complete peak and off-peak pricing for fuel costs,
which appears desirable.

G. Price Elasticity

The issue of price elasticity has often been raised in connection
with redesigning electric rates. The most successful advocates of
redesign have distinguished the issue of whether the new rate struc-

190. Id. at 503-05.
191. Id. at 506.
192. See Dunham, The Consumers' Stake in Nuclear Power, 95 PuB. UT.. FoRT.

19 (April 24, 1975).
193. Base load units are subject to scheduled maintenance which is performed

off-peak, but in general these units are designed to operate at a minimum load
throughout the year.

194. Consol. Edison Co., Case 26806 (N.Y.S. Pub. Serv. Comm'n.).

951975]



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

ture will produce a reduction in electricity consumption from the
notion that rate redesign is cost-justified regardless of whether or
not it results in reduced consumption. The latter argument has
been more readily accepted by those, commissions which are statu-
torily mandated to establish non-discriminatory rates.

Thus the foregoing rate design techniques (elimination of de-
clining block rates, institution of peak pricing and seasonal differen-
tials, etc.) can be analyzed and evaluated simply with respect to
their cost justification, since most commissions have viewed price
elasticity issues as corollary to the major focus of rate redesign.
Benefits gained from reduced consumption would be in addition
to those obtained by making rate structures more responsive to
costs of service.

The New York State Public Service Commission, in shifting its
emphasis from a value of service to an efficiency and incremental
cost of service basis for rate-making, has explicitly advocated the
use of willingness to pay, benefit, or value of service (which is a
direct function of price elasticity) only in situations in which rates
based exclusively on incremental costs yield companies inadequate
or excessive total revenues." And, in defining what may consti-
tute economically efficient rates, the Commission has left little
doubt that cost justification is paramount, and that beneficial re-
sults such as conservation will follow if prices truly reflect costs.
The Commission's theory, discussed previously,9 6 bears repetition
here:

An economically efficient rate structure requires that price reflect
external, e.g., environmental costs, as well as those explicitly
borne by supplying companies. Conservation clearly requires
the discouragement of such wasteful consumption as occurs
when prices are below cost, which is necessary for economic ef-
ficiency, as well. Thus, in principle, an economically efficient
rate structure should achieve the interrelated purposes of con-
servation and environmental protection.'97

Recent economic data indicate that the price of electricity, to a
certain extent, may indeed influence consumption. If this thesis is

195. Consol. Edison Co., Case 26538, 8 P.U.R.4th at 481.
196. See text accompanying notes 88-96 supra.
197. Consol. Edison Co., Case 26538, 8 P.U.R.4th at 479 (emphasis added).

96 [2: 40



Problems in Electric Utility Rate Design

borne out, rate redesign not only may assess more accurately cus-
tomer costs, but it may mitigate the need for the kind of rapid
growth which utilities have forecast. A study done in 1971 by John
Wilson, a Federal Power Commission economist, contained evidence
that the residential price elasticity of demand for electricity is -1.33;
that is, a 1% increase in the price of electricity produces a decrease
of 1.33% in demand." The Mount, Chapman and Tyrrell studies,
performed at Oak Ridge National Laboratories (ORNL), used a
time series analysis of 48 states in the 1946-70 period.""9 The ORNL
studies found long-run price elasticities of residential demand for
the three states in the New York metropolitan area in the range of
-1.23 to -1.47.200 Of course, the pressing question raised by these
studies is whether the elasticity measured in a period of declining
prices will be mirrored and found applicable in current and future
periods of anticipated increased prices. To test the symmetrical
validity of the ORNL results, a cross-sectional study was done by
New York University under the direction of Dean Netzer.2 ox Mark
Menchin analyzed residential elasticity in eighteen counties in the
New York metropolitan region using 1970 data. The results com-

198. Wilson, Residential Demand for Electricity, 11 Q. REV. ECON. & Bus. 7
(Spring 1971).

199. The following short-run and long-run elasticities were found:

Short-Run Long-Run

Residential -0.09 to -0.15 (OLS) -0.76 to -1.00 (OLS)
-0.25 to -0.27 (IV) -0.87 to -0.96 (IV)

Commercial -0.10 to -0.13 (OLS) -- 0.80 to -1.04 (OLS)
-- 0.71 to -0.81 (IV) -0.87 to -0.99 (IV)

Industrial -0.12 to -- 0.16 (OLS) -0.99 to -1.27 (OLS)
-0.80 to -1.08 (IV) -1.02 to -1.38 (IV)

Note: IV = Instrumental variables
OLS = Ordinary least square regression

(Source: Mount, Chapman & Tyrrell, Electricity Demand in the United States: an
Econometric Analysis, Oak Ridge National Laboratory, NSF-EP-49, June 1973.)

200. D. Netzer, Electric Energy Supply in the New York Area: Environmental
Damage, Economic Development and the Political Decision-Making Process, April
1, 1975, at 27 (unpublished report in N.Y.U. Graduate School of Public Administra-
tion Library).

201. Netzer, supra note 200.

1975] 97



98 COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

pared favorably to the results of previous studies.2 The statistically
best elasticities were found in the range of -1.0 to -1.3.

Even though much evidence supports the theory that as the
price of electricity increases demand will be reduced, it may be
unwise to tie electric rates to estimates of elasticities. If a peak/off-
peak pricing system were established with wide differentials be-
tween the two rates in accordance with user costs on the system,
costs would be tailored to users. In addition, to the extent that
price elasticity is experienced at peak periods,2 0

3 construction re-
quirements would be reduced. The peak and off-peak rates could
be apportioned to achieve the overall revenue requirement with
long-run incremental cost employed as part of the rate determining
factor. Finally, with a greater incentive for channeling reduced
consumption due to energy conservation into peak periods, there
is a greater possibility of stopping the trend of decreasing revenues
caused by energy conservation, since construction requirements
and revenues to cover them will be brought into phase.

V. CONCLUSION

As regulatory commissions throughout the country accept the
validity of new pricing theories for electric utilities, they will be
confronted with a series of difficulties in constructing and imple-
menting a modernized rate design. The New York State Public
Service Commission has recently initiated a generic rate procedure
to determine rate design policy for all the utilities in the state and

202. Id. at 28. Comparing his results directly to those of Anderson and Wilson,
using models employing a similar range of variables, the price elasticities are:

(1) NYU-Menchin -1.299
Rand-Anderson -0.91,

(2) NYU-Menchin -1.35
Wilson -1.33b

'The other independent variables are: natural gas prices, household income,
household size, winter and summer temperatures and, in Menchin only, the number
of households.

bThe independent variables are those specified in the preceding note, less sum-
mer temperatures.

(Source: Netzer, supra note 200, at 27.)

203. Testimony of Dick Netzer, supra note 127, at 9914-15.

[2: 40



Problems in Electric Utility Rate Design

to investigate methods of implementing new forms of pricing.2 04

Questions under review include how to determine incremental
prices and for what time period the increment is to be measured.
This is a problem, since utilities have various types of plants which
may be utilized in different combinations at any given time during
the day or during the year, depending on the load to be provided.
In theory, there are an infinite number of incremental time periods,
each associated with a different operating or capital cost which
could be charged to customers.

Commissions may have to balance a desire to achieve, on the
one hand, a precise correlation between users and the incremental
costs for which they are responsible and, on the other, a relative
stability of rates. Obviously, a utility tariff can not be changed so
frequently that customers are unable to make intelligent purchasing
decisions. Such an approach would undermine the entire effort to
change rate structures, which is predicated on the belief that con-
sumers will make efficient choices when charged for the costs they
actually impose on the system. If these efficient choices are made,
the need to build new plants at a greatly increasing cost per unit,
dictated by growing use at the peak, will be tempered.

Determining what period constitutes the "peak" period of maxi-
mum demand is also a difficult task. If significant differentials are
to be applied to peak and off-peak usage, then the relation of time
of consumption to the need to build new additions to existing plant
takes on considerable importance. If a utility designs its system for
an 8,000 MW capacity which is attained at 3:00 P.M. on a hot sum-
mer day, should customers using electricity at 2:59 P.M. on that day
be charged the peak or off-peak price? Where should the peak
period cut-off point be?

When the concept of incremental pricing is fully explored, dif-
ficult questions arise, including whether usage by new customers
or increased usage by existing customers constitutes significant mar-
ginal demand on the system. Or perhaps all customers who take
any power in the peak period may be regarded as imposing the
significant marginal demands on the system since, at least in theory,
they have the option of not taking additional service at all or not
taking it at the peak period.

204. Consol. Edison Co., Case 26806 (N.Y.S. Pub. Serv. Comn'n.).

1975] 99



COLUMBIA JOURNAL OF ENVIRONMENTAL LAW

Also at issue is whether the economists' notion of what consti-
tutes an incremental capacity cost can be practically incorporated
in a price system. In theory, the marginal cost is only for new addi-
tions to plant, and the historic costs of the existing plant are largely
to be ignored in setting marginal rates. Yet, basing current rates on
future additions to the plant defies the traditional notion that rates
should be set on the basis of the plant which is already in service
in order to avoid charging present customers for the plant they have
not yet used. Furthermore, if peak period users are to pay only for
additions to capacity, the revenue raised may fall short of that re-
quired to insure an adequate rate of return on the overall invest-
ment.

It has been suggested that the difference in revenues be made up
by increasing the charge to customers who have relatively inelastic
uses (i.e., as the price to them increases, they do not markedly alter
their demands). However, since the science of determining price
elasticity is thought quite imprecise, especially by those who are
most skilled at making such calculations, many have questioned the
wisdom of apportioning what could be substantial rate increases to
customers based on the strength of these studies.

The New York State Public Service Commission's generic rate
proceeding has confined itself primarily to determining rate design
questions and, to date, the issue of determining the revenue re-
quirement has been considered largely out of the proceeding's prop-
er bounds. However, as issues of apportioning excess or deficient
revenues arise, it is apparent that considering one without the other
may prove unduly restrictive. In any event, as the Commission
struggles to find a method of merging the theory with a practical
way of implementing marginal cost pricing, it will have an oppor-
tunity to solve current utility problems and establish valuable
precedents for commissions in other states.

100



Columbia Journal of Environmental Law
SCHOOL OF LAW, COLUMBIA UNIVERSITY

VOL. 2 FALL 1975 NO. 1

BOARD OF EDITORS

John J. Kerr, Jr.
Editor-in-Chief

Michael M. Gordon
Ralph W. Austin
Articles Editors

Jeffery H. Sheetz
Case Editor

Robert C. Hayn
Book Review Editor

John W. Wagstaffe
Forum Editor

Jeffrey M. Gaba
Edward N. Maurer

Thomas E. Winslade
Notes & Comments Editors

Douglas R. Chamberlain
Subscriptions Editor

John M. Christian
Managing Editor

STAFF

David L. Bersohn
Joseph M. Bleshman
Mark A. Conley
Ralph C. Coti
Barry F. Davidoff
Kathryn M. Downing
David A. Emil
Robert I. Field

Philip E. Foster
Alan S. Kaufman
Robert S. Kutner
Catherine R. McCabe
Gregory V. Redlitz
Walter G. D. Reed
Suzanne E. Schwartz
Robin B. Stone
Sheldon L. Trubatch