Arvid E. Kruze
April 10,1998
Introduction
Hydro Quebec’s proposal to the Régie de l’énergie, titled “Modalités d’établissement et
d’implantation des tarifs de fourniture” and dated February 20, 1998, is in response to
Article 167 of the “Loi sur la Régie de l’énergie” (subsequently referred to in this text as
the “Law”), which was made effective by Government of Québec on February 11, 1998.
The above article orders the Régie to provide a notice to the Government, upon receipt
of a proposal by Hydro Québec, on the modalities of establishing and implementing
tariffs for the provision of electricity to a customer or a category of customers. This
order is further subject to Article 52 of the same Law which essentially states that the
tariff must reflect the real costs incurred by a producer of acquiring the electricity and
providing it to distributors, as well as considering the consumption of the customer or
category of customers.
In addition, Hydro Québec has interpreted the provision of power, as set out in the Law
(“fourniture”), to mean the component of electricity supply related only to production,
which is only one functional area of electricity supply, the two other main functions
being transmission and distribution.
Given the above, Hydro Québec has then proceeded in its proposal to develop a
formula for deriving a production tariff for each different type of consumer based on
Hydro Québec’s present high voltage supply tariff (known as Tariff L) less transmission
costs and then adjusted for load factor and voltage level of supply which is intended to
reflect the usage differences between the various types of customers.
The purpose of this critique is to first explain why the methodology used in Hydro
Québec’s proposal is flawed and to then present the proper method of developing a
production tariff as required by the Law.
Deficiencies of Hydro Quebec’s proposal
The two most apparent flaws in Hydro Québec’s proposal include the following:
1.
The whole process of generation (supply) tariff determination is not directly and
explicitly based on cost as stipulated in Article 52 of the Law. Indeed, the
derivation of the tariff begins with an existing tariff that has no explicit relationship
to the cost of production. Tariff L, by definition, is not a cost. Thus, the
requirements of the Law are not addressed.
2.
The development of the tariff does not follow a very basic tenet normally
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employed by most, if not all, electric utilities involved in tariff development; that
is, to first estimate the cost of the service provided before considering other
possible factors to actually set the tariff. In this particular instance, however, the
Law is quite clear in stating that the production tariff must reflect the real cost (of
production).
Conformance with usual tariff setting practices
With respect to second item above and, specifically, “normal” tariff setting principles
employed in the electric power industry, it would be useful to evaluate Hydro Québec’s
proposed tariff against the ten attributes of a sound tariff structure first identified by
Bonbright 1 in what is judged by many tariff practitioners to be a classic text on the
subject. Although the context of the ten attributes is best understood within a retail
tariff structure, each attribute can also be used to examine the merits of a single tariff.
These ten attributes are summarized on Exhibit 1.
Below is an evaluation of Hydro Québec’s proposed production tariff with reference to
each of the above attributes, followed by a judgement as to whether the tariff
possesses that attribute.
1.
Effectiveness in yielding total revenue requirements. In the context of a
deregulated transmission and generation market, as confirmed in the Hydro
Québec proposal, this attribute should be understood as a supply side
(generation) revenue requirement. Because the revenue requirement of Hydro
Québec’s production function is not even known, no appraisal of its effectiveness
in yielding total revenue requirements can possibly be made.
 NO
2.
Revenue stability and predictability. This depends largely on the stability and
predictability of a number of inputs, including Tariff L, the load factor of Tariff L
customers, the revenue requirement of the transmission function, the kW carried
by the transmission company and the load factor of the distributor. Without an
analysis showing that the resulting “production revenues” are, indeed, stable and
predictable, the number of inputs to the equation appear too numerous for one to
say that the tariff is stable and predictable.
 NO
1
Bonbright, James C., 1961. Principles of Public Utility Rates, New York, Columbia
University Press (this text was subsequently updated in 1988 by Bonbright, Danielson
and Kamerschen and published by Public Utilities Reports Inc., Arlington, VA)
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April 10,1998
3.
Stability and predictability of the rates themselves. Using the same argument as
above, how can one say that the rates are predictable and stable when subject
to changes in other various inputs?
 NO
4.
Static efficiency of the rate classes and rate blocks in discouraging wasteful use
of service while promoting all justified types and amounts of use. There is
absolutely no indication of whether the cost of production is actually provided.
Generally, tariffs that best reflect cost would be judged “statically efficient”.
 NO
5.
Reflection of all of the present and future private and social costs and benefits
occasioned by a service's provision. We do not know the costs.
 NO
6.
Fairness of the specific rates in the apportionment of total costs of service
among the different ratepayers so as to avoid arbitrariness and capriciousness
and to attain equity. Although the apportionment of the basic tariff (that is, Tariff
L less transmission costs) to the various types of customer appears to have been
conducted in a certain way, we do not know whether the starting point (total
costs) is correct. Hence, fairness for different ratepayers is not assured by
Hydro Québec’s proposal.
 NO
7.
Avoidance of undue discrimination in rate relationships. In this case, the
relationships between the rates derived for the various classes appear
reasonable, being based on customers’ load factors and losses incurred by
voltage level.
 YES
8.
Dynamic efficiency in promoting innovation and responding economically to
changing demand and supply patterns. This is always a difficult item to
evaluate. Although it is difficult to imagine a collection of single part energy
charges as being dynamically efficient, they are based on a number of inputs
which, if changed, will change the tariff. However, it would then have to be
assumed that Tariff L is dynamically efficient. One can give Hydro Québec the
benefit of the doubt.
 YES
9.
The related attributes of simplicity, certainty, convenience of payment, economy
of collection, understandability, public acceptability, and feasibility of application.
In the context of a completely unbundled electricity market where consumers
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would pay separately for production, one can say “no” to “simplicity” and
“certainty” because there are too many convoluted inputs to the tariff (imagine
trying to explain an increase in the production tariff because of an increase in
Tariff L), “yes” to “convenience of payment” and “economy of collection” (the
resulting tariffs being simple, single part energy charges), “no” to
”understandability”, “no” to “public acceptability” (that is, in a properly regulated
environment) and probably “yes” to “feasibility of application”.
 ½YES; ½NO
10.
Freedom from controversies as to proper interpretation. The methodology,
although convoluted in its logic, does not appear ambiguous. The resulting
rates are straightforward.
 YES
Awarding one point for every occurrence of YES (that is, conforming with Bonbright’s
attributes) and one point for every NO (not conforming with Bonbright’s attributes), the
total score is: YES 3½,
NO 6½.
Thus, it can be seen that Bonbright is not likely to give the proposed tariff his approval.
Consequences of not beginning with the cost of production
Aside from not adhering to the requirements of the Law and not rating high with
Bonbright, the consequence of not having an estimate of the cost of production is that
there is no benchmark or point of reference that can be used in assessing or in setting
the tariff. Because there is no such point of reference, estimates of the extent to which
the tariff is above or below the actual cost of service cannot be made.
It may be convenient to assume that Tariff L is set precisely the actual cost of providing
electric service and, therefore, can be used as a solid basis for deriving the cost of
production and, hence, the production tariff, in accordance with the Law. In fact, this is
probably not true, given the following:
1.
Hydro Québec never says in its proposal that Tariff L reflects the actual cost of
providing electric service.
2.
If Hydro Québec is like most utilities in the world, then the tariffs of its industrial
and commercial sectors subsidize residential customers. In other words,
industrial and commercial customers usually pay significantly more than the
utility’s cost of providing electrical service, while residential customers usually
pay significantly less than this cost. Of course, it cannot be said with absolute
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certainty that this is the case with Hydro Québec without first examining its cost
structure.
However, if the Tariff L is, indeed, based 100% on cost (and there are serious doubts
about this), then this should be clearly supported by a costing analysis of Hydro
Québec’s production and transmission functions right up to the point of sale with Tariff L
customers. In fact, if Hydro Québec had used this methodology, there would have
been no need at all to consider transmission costs in arriving at the cost of production
(except for those costs associated with high voltage lines used for carrying power from
the generating stations to the main grid).
The fact that it would have been more conventional, simple and straightforward to begin
the analysis with actual production costs immediately raises the question why Hydro
Québec goes through a rather convoluted exercise of attempting to “unbundle” an
existing transmission tariff for the purpose of arriving at a production tariff. And, the
obvious answer is to hide costs which Hydro Québec views as confidential, but which in
most regulatory environments, is open to public scrutiny. This situation only reveals
the incompatibility of Hydro Québec’s normal method of operating in a monopolistic
unregulated environment with the new regulatory regime currently being implemented in
the province.
Price signals
A final deficiency of Hydro Québec’s
proposed production tariff is in the provision of economically efficient price signals to its
customers. The current proposed tariff is in the form of a single part energy charge
which does not provide any signal to customers on the actual production cost of
electricity, which is dependent on the amount of energy being consumed, the rate at
which it is being consumed, and, finally, the time of day and year it is being consumed.
In open power “spot” markets, where electricity is bought and sold on the basis of
capacity “blocks” over time and the price is, by necessity, usually expressed as a single
part energy charge, sending the correct price signal to consumers is not an issue.
This is because the blocks are generally sold and purchased over short periods of time
(e.g., hours). In this context, the market dictates the price paid for the power at any
point in time and, as a result, economic efficiency arises from supply and demand in the
marketplace.
This is different from the situation found in a vertically integrated electric utility where
there is a long term commitment by the utility to sell electricity to customers. In this
case, it is not considered economically efficient to set a uniform price for all electricity
sold over the course of, say, a year. It is normal practice that proper price signals are
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built into the tariffs which reflect the fact that the price of electricity varies based on
customers’ usage patterns. These price signals include a demand charge as well as
an energy charge, either of which can be different over time (although the specific
charges by time period would be predetermined, as opposed to being set by market
forces).
Hydro Québec’s proposed single part energy charge for each category of service
considers such usage patterns in their calculation. However, the charges lose their
effectiveness in providing the appropriate price signals to consumers when they are
averaged over time and over a large number of kWh.
Possible methods for deriving the production tariff
It should first be emphasized that costing and tariff setting are two distinct processes.
Tariff setting is based largely on costing, but the reverse is not true. However, many
other factors generally influence tariff design, especially at the retail level. These
include political and socio-economic considerations, metering constraints, price
elasticity of demand, economic effectiveness, providing intended price signals not
necessarily based on cost, effectiveness in yielding total revenue requirements,
revenue/ tariff predictability and stability and, finally, many of the previously mentioned
“practical” aspects identified by Bonbright.
Whatever the factors are that finally influence a tariff, costs are generally the major
determinant.
The purpose of this section is to describe various accepted methods that could have
been used by Hydro Québec in its proposal, beginning from costing principles.
Cost of service
Cost of service is the primary basis used for any study or analysis of electricity tariffs,
as any utility must, over the long run, recover through its tariffs the costs associated
with providing electrical service.
The “revenue requirement”, or “total cost of service” of an electric utility (or portion of an
electric utility, such as the production function) comprises the financial components of
operating and maintenance expenses, depreciation, income taxes, interest expense
and return on equity. The total of the these costs can be viewed as a "pie", as
illustrated in Exhibit 2. As pointed out in the evaluation of Hydro Québec’s proposed
tariff in the previous section with respect to Bonbright’s first attribute of effectiveness in
yielding total revenue requirements, there is no such revenue requirement defined in
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the development of Hydro Québec’s proposed tariff.
The cost allocation process involves partitioning this revenue requirement (or total cost)
into revenue (or cost) segments to be collected from the various customer categories,
as can be seen on the bottom circle in Exhibit 2.
As will be seen, there is wide latitude among the possible methods that can be adopted
in determining the revenue requirement by category of customer. Each method has its
proponents and critics. First, there is a choice between using accounting costs and
marginal costs. Then, within these two broad categories of costing methodology,
various other methods have been used and debated within practically all the regulatory
jurisdictions in North America. For example, an often recurring debate with respect to
accounting costs (as well as marginal costs, to a certain extent) is the “correct” way of
allocating demand related costs. With respect to marginal costs, many marginal
costing methodologies have been proposed since the concept first surfaced in the
1970's, but the most general debate appears to have centred on the merits of using the
“peaker” methodology versus an “expansion plan” or “incremental revenue
requirements” approach.
It is not within the scope of this critique to suggest a costing methodology. This is a
matter that can be settled once Hydro Québec is able to produce a tariff proposal in
which the full details of a supporting cost study are also presented. In most regulatory
jurisdictions, the costing methodology behind a tariff proposal such as Hydro Québec’s
would be subject to public review. In many cases, the regulatory board would have
already developed its own opinion on the methodology that should be used (sometimes
in great detail) and ordered the utility to follow it. It is entirely possible that this order
would have been based on a public hearing specifically held to debate costing
methodologies.
In the USA, where the electric utility sector is changing rapidly because of deregulation
and the eventual creation of open markets even in the residential retail sales area, the
issue of production cost being heard in an open public forum is becoming less of an
occurrence simply because the regulation of production costs is irrelevant in an open
market. So far, this is not the case in Québec, where, for the foreseeable future at
least, Hydro Québec is expected to retain a monopolistic position from the production of
power down to the retail sales level. Therefore, for the sake of price efficiency in the
Québec power sector, the Régie has no choice but to regulate costs.
One of the best references on costing for tariff setting purposes is the “Electric Utility
Cost Allocation Manual”, published by the National Association of Regulatory Utility
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Commissioners (NARUC) in Washington, DC2 This manual covers nearly all aspects
of electric utility costing from a regulatory perspective.
As described in the NARUC manual, there are two basic types of costing methodology
in use, namely, I) accounting (or embedded) costs and ii) marginal costs.
Accounting versus marginal costs
A utility’s revenue requirement (or that of a utility’s production function) is based on
accounting costs which are, essentially, "backward-looking" because financial reporting
requirements reflect what has happened during a past period. On the other hand,
economic theory dictates that the best way to assure efficient use of resources in the
production of electricity is to price at the additional (or marginal) cost of providing for a
particular additional use, considering the particular quantity and the particular time and
place of use. If electricity tariffs were based on marginal costs, each consumer
presumably could judge better whether and when to use electricity in various ways.
This requires a "forward-looking" approach in order to anticipate the cost of the next kW
or kWh.
Since the 1970's (at about the time it was realized that energy is a relatively scarce
resource), greater emphasis has been placed on economic efficiency and therefore, on
marginal cost concepts in electric utility tariff design. These concepts are useful for the
purpose of incorporating appropriate price signals within the tariff structure.
However, most electric utilities tend to regard marginal cost pricing as a useful tool or
an aid in tariff design, not a complete solution. Actual marginal costs are rarely used
as prices and a minority of North American electric utilities use marginal costs for
purposes of cost allocation. The reason for this is that marginal costs are different
from financial costs (or accounting costs) which are the governing costs in the
measurement of performance. If marginal costs are above financial costs, the utility
would be seen as "over-earning" if it priced electricity at marginal cost. If marginal
costs are below financial costs, then the utility would not earn enough to be a financially
viable entity.
Therefore, marginal costs are generally used as a guide for tariff design and are also
used for cost allocation purposes. Usually, it is accounting costs in total that
predominate, but with marginal cost concepts built into the costing or tariff structure.
2
National Association of Regulatory Utility Commissioners, 1992. Electric Utility Cost
Allocation Manual, Washington, DC
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Cost of service procedure based on accounting costs
There are, in general, six basic steps to allocating accounting costs. These steps are
illustrated on Exhibit 3. Below is a more detailed description of these steps, together
with a very simplified example (it should be noted that the costing exercise is much
more complex than might be suggested by the example which is meant only to very
generally illustrate the basic concepts):
Step 1.
Assemble "basic data", which, for the purpose of developing a production
tariff, would include the following information:
consumptions
demands
detailed statement of fixed assets related to production
detailed income statement for the production function
production statistics, including energy and peak production
energy and peak load losses by voltage level
It should be noted that the above is not comprehensive in terms of total
data requirements for a cost of service analysis, but forms the major part
of the data requirement. Many other inputs regarding certain physical
characteristics of the power system are often required for the purpose of
allocating costs (eg., how much of the utility's transportation equipment is
production related? transmission related? distribution related?).
To illustrate “basic data” for the purpose of showing a very simple
illustrative example, assume a system having a peak load production of
30,000 MW from hydro sources and annual energy production of 160,000
GWh. There are two customer categories served by the system: i)
Residential, having an consumption of 80,000 GWh (including sales and
an allocation of system losses) and a corresponding peak load
contribution of 20,000 MW ii) Industrial/ Commercial, having a similar
consumption of 80,000 GWh and a corresponding peak load contribution
of 10,000 MW. Assume a total revenue requirement of $3.0 billion,
based on depreciation on production assets of $1.6 billion, operating and
maintenance expenses of $0.8 billion and a profit of $0.6 billion.
Step 2.
Derive allocation factors for each category based on energy, demand and
customer related statistics.
The general principle behind the
development of the cost allocation factors is that a customer category will
be allocated a proportionate amount of the costs for which it is
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responsible. In the simple example, because the Residential category
accounts for 50% of energy generated, it will have 50% of all energy
related costs allocated to it (and, likewise for Industrial/ Commercial).
Also, because the Residential category accounts for 67% of peak
demand, it will have 67% of all demand related costs allocated to it and, in
a similar fashion, the Industrial/ Commercial category will have 33% of all
demand related costs allocated to it3. Because customer related costs
are incurred only in connection with the distribution and commercial
functions, there are no customer related costs at the production level.
Step 3.
Functionalize costs. In a fully integrated cost of service analysis, costs
shown on the detailed statements of income and fixed assets need to be
"functionalized" into summary accounts that will facilitate their definition
into energy related, demand related and customer related components.
This is done at least by main function (ie., production, transmission,
distribution). In the example, there is only one function but production
and it is assumed that all costs attributable to production are included. It
is important to note that other than the direct costs of production, this cost
should also include its fair share of the utility’s indirect costs such as
admin and general. Also, if there are significant transmission facilities
required to bring the power to the main grid, then the cost of these
transmission facilities should be included as part of the production
function.
Step 4.
Allocate costs to major cost components. Functionalized costs are then
classified as energy related, demand related and customer related.
Generally, a detailed examination of the functionalized costs in each of
the main revenue components (operating and maintenance, depreciation,
profit) would result in different splits between energy related, demand
related and customer related. This, in itself, can be a complex exercise.
In the simplified example, however, let it be assumed that the utility has
found all of its production costs to be 67% energy related and 33%
demand related. Therefore, the utility’s total revenue requirement of $3.0
billion in this case would be $2.0 billion energy related and $1.0 billion
demand related.
Step 5.
Allocate cost components to customer categories using allocation factors.
3
This corresponds to only one method of allocating demand related costs. The question
of the most appropriate method for allocating demand related costs has always been
controversial.
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In this step, allocation factors from Step 2 are applied to costs classified
in Step 4 to arrive at total costs allocated to each customer category. For
each of the categories in the example, total costs would then be
calculated as follows:
Residential: Energy cost = 0.5 x $2.0 billion
= $ 1.00 billion
Demand cost = 0.67 x $1.0 billion = $ 0.67 billion
Total
= $ 1.67 billion
Industrial/ Commercial:
Energy cost = 0.5 x $2.0 billion
= $ 1.00 billion
Demand cost = 0.33 x $1.0 billion = $ 0.33 billion
Total
= $ 1.33 billion
Thus, the total revenue requirement of $3.0 billion has been completely
allocated.
Step 6.
Summarize results. The actual allocation exercise has been performed
in the previous steps. Depending on how the allocated costs will be
used, they can be appropriately summarized. The above results can be
expressed on a per kWh basis. For example, if total Residential sales
are equal to 74,000 GWh, then the average Residential production cost
would be equal to about $0.0225 per kWh. Based on sales of 77,000
GWh, the corresponding Industrial/ Commercial tariff would be $0.0173
per kWh. Another method that would provide better information for tariff
setting purposes would be to express only the energy cost on a per kWh
basis and then, the demand cost on a per kW delivered basis for the
Industrial/ Commercial customers and on a per customer basis for
Residential.
Cost of service based on marginal costs
Marginal cost, as it relates to the supply of electric power, may be defined as the
incremental cost of optimum adjustments in the system expansion plan and system
operation attributable to an increment of demand which is sustained into the future.
Thus, marginal cost attempts to quantify the cost of the additional kWh or kW
demanded.
The rationale for using marginal costs as the basis for electricity pricing is to direct the
consumer, through the price charged for electricity, towards the most efficient use of
resources available. Theoretically, if price is equal to the marginal cost of supply, an
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optimal allocation of resources, or economic efficiency, will result. This is because the
customer is provided a signal of the cost of his incremental demand for energy and
capacity. He then decides whether or not to consume more. Through this process,
tariffs based on marginal cost principles should persuade customers to make efficient
choices when considering the use of energy resources in any of its forms, thus leading
to a more efficient allocation of all energy resources.
However, the revenue requirement, or total cost of service of an electric utility, normally
comprises a number of financial components, which may include operating, fuel and
maintenance expenses, depreciation, income taxes, interest expense and return on
equity. In other words, the total revenue that is required from tariffs is usually not
based on marginal costs, but on the financial costs incurred. Therefore, for tariff
development, marginal costs must be adjusted so that the revenue collected is equal to
the financial requirement.
Despite this incompatibility, marginal cost of service can be a powerful tool in the design
of tariffs in a number of ways. First, marginal costs can be used as the basis to
partition the utility’s total revenue requirement into segments to be collected from the
various customer categories, as illustrated in Exhibit 2. Second, certain unit marginal
costs can be used as tariff components to send the correct price signals to consumers
so that electricity is consumed in an economically efficient manner.
Many marginal costing methodologies have been proposed and used throughout the
world. Although similar in their goals of attempting to quantify the marginal cost of
electricity supply, many of these methodologies are very different in their application.
Because this can be the topic of an entirely separate debate (which has been argued
extensively in many public hearings throughout North America over the years), there is
no point in describing different marginal costing methodologies in this writeup. Again,
this is an item that can be addressed once Hydro Québec is able to produce a tariff
proposal in which the full details of a supporting cost study are presented.
However, a very simple example of how marginal costs might be applied under one
such method, the “proxy plant” approach, is described below, in the context of the
previous example used for the costing of power on the basis of accounting costs. It
should be noted that the “proxy plant” approach has been chosen in this example only
because of its simplicity and there may arguably be better marginal costing
methodologies that can be applied.
Suppose the same utility has sufficient load growth to justify constructing a hydro plant
over the next few years having a firm peaking capacity of 2,000 MW and a total cost of
$6 billion, which includes the present worth of all future investment and operating costs.
Also, the utility has determined that 60% of this cost is energy related and 40% is
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demand related. Therefore, the present worth of marginal energy related costs is $3.6
billion and the corresponding demand related cost is $2.4 billion. Assuming a 50 year
life for the plant and an annual cost of capital of 10%, this amounts to just over $360
million and $240 million, respectively, on an annualized basis. Given that the plant will
produce 13,000 GWh annually, the marginal energy cost is then equal to $0.0277 per
kWh (that is, $360 million divided by 13,000 GWh). Also, assuming that the 2,000 MW
installed capacity is required to serve an incremental load of 1,740 MW (in other words,
the utility has a reserve margin criterion of 15%4), the marginal demand related cost per
kW is then equal to $138 per kW per year (that is, $240 million divided by 1,740 MW),
or about $11.50 per kW per month (that is 138 divided by 12). The total marginal cost
of the plant, including both energy and demand components and expressed on a per
kWh basis, is about $0.046 per kWh (that is, $(360 + 240) million divided by 13,000
GWh).
It is more expensive to produce power during peak periods than at other times and this
would be reflected in a more detailed marginal costing analysis. In the above example,
the $0.046 per kWh total marginal cost can be broken down into components including
a cost for peak energy, a cost for offpeak energy, a cost for peak demand and cost for
offpeak demand. If judged necessary, another period, often called the “shoulder” or
“partial peak” period (which is somewhere between the peak and offpeak periods) can
be defined. There are various ways that marginal costs can be time differentated, but
again, a dissertation on these methods is beyond the scope of this writeup.
The above unit costs are expressed in terms of output from the plant (or, if there are
significant transmission facilities required to bring the power to the main grid, then the
costs would be expressed in terms of the output from these transmission facilities).
Adjustments to these costs would then be made to reflect the cost of electricity
delivered to customer premises.
If the above unit marginal costs are compared with the unit accounting costs derived in
the previous section, it can be seen that the marginal costs are substantially higher.
This illustrates a typical situation where, if the utility charged for electricity at full
marginal cost, there would be an “over” collection from a financial perspective.
Therefore, adjustments to the unit marginal costs are necessary.
The task of adjusting unit marginal costs is made easier by the fact that marginal costs
4
For the purpose of having a suitable reliability level in being able to meet the load, electric
utilities typically install capacity over and above the forecast demand. This contingency
between forecast demand and installed capacity is referred to as the “reserve margin”.
An often used simple “rule of thumb” for estimating the required reserve margin is to take
15% of forecast demand.
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are most often time differentiated and broken down into energy related and demand
related components. Since the most important concept behind the notion of marginal
cost pricing is to send a correct cost signal to consumers at the proper time, some
components of the unit marginal cost can be adjusted more than others. For example,
a correct cost signal at 3:00 am is less important than a cost signal during the peak
period at, say, 6:00 pm. Also, there are sound theoretical bases for suggesting that
the energy price signal is more important than the demand price signal in eliciting
consumer responses. Therefore, once unit marginal costs have been established in
terms of energy related and demand related costs incurred during the peak period, the
offpeak period and, possibly, a “shoulder” period, some of these various cost
components can be adjusted downward more than others so that the total financial
requirement is met.
The tariff setting process
Only once the costs are known can tariffs be developed.
As previously discussed, there are a number of factors other than cost which can
eventually affect the development of a tariff. However, attention to cost must always
be a primary consideration.
Political and socio-economic factors, for example, dictate that the price paid for
electricity in remote load centers isolated from the main Hydro Québec grid is the same
as that in the rest of the province, even though the cost of producing this electricity is
much greater. This policy also results in urban consumers paying the same rates as
rural consumers, even though the cost of providing electricity in an urban environment
is generally much lower than in rural areas. As previously mentioned, residential
customers are likely to be subsidized by commercial and industrial customers.
Metering constraints dictate that not all components of cost can be adequately charged
to customers. The best example of this problem is that meters capable of measuring
maximum demand as well as energy are relatively expensive and therefore, are not
generally used on small consumers such as residential. Therefore, the residential tariff
cannot have a demand charge. This cost might then be recovered either through a
monthly customer charge or added to the energy charges. However, there can be no
demand charge which is theoretically the best price signal.
Price elasticity of demand, or the extent that consumers will react to changes in prices
is another factor which might influence tariffs. Some customer categories might be
more sensitive to price changes than others and will change their consumptions
accordingly. Other customer categories will not. Therefore, with the goal of
maximizing sales revenues, electric utilities might have a tendency to price power to
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April 10,1998
less sensitive customers at a higher level and price power to sensitive customer groups
at a lower level.
Providing intended price signals not necessarily based on cost has been a tool used by
some electric utilities for the purpose of promoting the sale of electric hot water heaters,
for example.
Thus, it can be seen that there are factors other than cost which can influence the
development of a tariff. The factors cited above are by no means exhaustive.
Regulatory bodies often consider many of these factors in their judgements and provide
appropriate rationalizations for doing so.
Once costs and all other tariff setting criteria are known, then tariffs are developed.
The level of tariff for each customer category is normally determined based on a
forecast revenue target for that category. Based on the discussion in the preceding
paragraphs, the revenue target for each category will be equal to the forecast cost of
providing electric service less (plus) the net total of all other considerations. The total
forecast revenue collected from all categories must be equal to the revenue
requirement of the electric utility (or, in the case of Hydro Québec’s proposal, equal to
the revenue requirement of the production function).
The importance of transparency
As a result the many influencing factors discussed above, there will be cross
subsidization
within a tariff structure. Also, costing exercises cannot possibly be conducted to a level
of detail such that everyone is allocated a cost in proportion to his own specific usage of
system resources. Costs must be averaged among groups of customers, even though
the cost of service to individual customers within each group will vary. Therefore,
within any tariff structure, there will always be subsidies even if there is an honest
attempt to price at cost.
In any case, if subsidies in the tariff structure are significant, one should be able to
quantify them for the sake of transparency. The cost of providing electric service is an
essential point of reference in being able to calculate the size of a subsidy. Otherwise,
nobody would know the extent of the subsidy or that it even exists.
There is no indication of the relationship of Hydro Québec’s proposed production tariff
to the underlying costs of production. Therefore, there can be no rationale provided for
any deviation from cost. As a result, nobody can possibly assess the adequacy of the
tariff.
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Arvid E. Kruze
April 10,1998
Respectfully submitted on April 10, 1998
Arvid Kruze
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