RÉGIE DE L’ÉNERGIE
FILE R-3398-97
APPLICATION RELATING TO
LOI SUR LA RÉGIE DE L’ÉNERGIE, ARTICLE 167:
METHODOLOGY FOR DETERMINING
THE CONDITIONS OF
ESTABLISHING AND IMPLEMENTING
RATES FOR SUPPLYING ELECTRICITY
EVIDENCE OF
JOHN TODD
ON BEHALF OF
OPTION CONSOMMATEURS
ET
LA FÉDÉRATION NATIONALE DES ASSOCIATIONS
DE CONSOMMATEURS DU QUÉBEC (FNACQ)
MAY 5, 1998
INTRODUCTION
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The first paragraph of article 167 of An Act respecting the Régie de l’énergie (Loi sur la
Régie De l’énergie, the “Act”) states:
167.
On the proposal of Hydro-Québec, the Régie shall, within six
months of the coming into force of this section, advise the Government on
a procedure for the determination and implementation of rates for the
supply of electric power in respect of a consumer or class referred to in
section 52.
Article 52 states:
52.
In any tariff for the supply of electric power or natural gas, the
rates and other conditions applicable to a consumer or class of
consumers must reflect the actual cost of acquisition to the distributor or
any other terms granted to the distributor by producers of electric power or
natural gas or their representatives in consideration of the consumption of
that consumer or class of consumers.
A tariff may also reflect any other acquisition-related cost of the
electric power or natural gas to the distributor.
The Act appears to be consistent with the standard practice in other Canadian
jurisdictions for setting rates for electricity and natural gas, which is to establish
cost-based rates using an approach referred to as rate-base rate-of-return regulation.
The standard practice consists of the following steps.
Determine the regulated company’s total revenue requirement based on its
·
actual costs (essentially, current operating and maintenance expense, plus
current depreciation expense at allowed rates of depreciation, plus the cost of
capital1).
1
The cost of capital is equal to the actual cost of debt plus an allowed return on equity, at
the allowed capital structure. For a investor-owned utility, the capital structure and the
return on equity are based on capital market considerations - the return needed to attract
new equity capital. In the case of government-owned utilities, the return that is allowed
on the company’s equity, or retained earnings, relates more to debt market
considerations, government/regulatory policy regarding financial soundness, distributions
to government, etc..
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Allocate the costs to customer classes based on a formal cost of service study
that functionalizes, classifies and allocates the company’s revenue requirement
in a manner that reflects cost causality.2
·
Design rates that collect revenues from each customer class that roughly
accord with the costs allocated to each class. In general, regulators seek to
keep the revenue-to-cost ratios of all customer classes receiving firm service
within a zone of reasonableness.3
The process for setting cost-based rates is normally reviewed through a regulatory
process that ensures transparency so that each customer class has the opportunity to
review the companies’ cost allocation methodologies in detail. This review process is
part of the regulators’ exercise of due diligence to ensure that rates are just and
reasonable.
Hydro-Québec’s Application and Proposal
Hydro-Québec filed an Application, dated 20 February 1998, pursuant to article 167
which concludes:
2
The three steps in the cost of service study are:

functionalize: expenses and rate base are separated by cost functions such as
generation, transmission (domestic and export), sub-transmission, distribution,
customer service and direct;

classify: functionalized costs are separated by classes of costs such as energy
(commodity), demand (capacity) and customer; and

allocate: functionalized and classified costs are allocated to customer classes
based on allocators such as annual energy consumption, seasonal energy
consumption, peak day demand, seasonal/monthly/daily peak demand, number
of customers.
Different companies and jurisdictions used different cost functions and classes. A wide
range of allocators are used by different companies and jurisdictions. These difference
arise because cost of service studies require the exercise of discretion and judgement to
ensure that each study reflects the unique cost characteristics of the company.
3
For example, it is common to rate rebalance if the revenue-to-cost ratio for any class is
outside a zone or reasonableness of 0.90 to 1.10.
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IN CONCLUSION, HYDRO-QUÉBEC REQUESTS THE
RÉGIE DE L’ÉNERGIE TO ADVISE THE GOVERNMENT
AS FOLLOWS:
THAT the procedure for the determination and
implementation of rates for the supply of electric power be
established in accordance with paragraphs 6 to 15 of this
application.4
The essential elements of the Hydro-Québec proposal for the determination of rates
appear to be as follows.

Separate the generation, transmission 5 (TransÉnergie) and sales functions in
the wholesale market.

The cost of generation will be based on the implicit generation cost that is
included in current rates, calculated as tariff L minus the approved transmission
cost.

The initial supply price (le prix initial d’acquisition de la fourniture) charged to
customers by Hydro-Québec (the Distributor) will be based on the derived cost of
generation, adjusted to reflect the load factor (le facteur d’utilisation) and the
average loss rate (le taux de pertes moyen) of each customer or customer class.
This approach implicitly assumes that current prices reflect costs, although
current prices are not based on a cost of service model that has been subjected
to public scrutiny.

The supply price will be adjusted each year to reflect changes in the load factor
and loss rates of each customer or customer class.

The transmission cost will be TransÉnergie’s revenue requirement and the
transmission rates will be based on this cost divided by the sum of the monthly
peaks of the transmission network for 1998.6
4
The RNCREQ translation of the Application Concerning Hydro Québec’s Proposal to
Establish a Procedure for the Determination and Implementation of Rates for the Supply
of Electric Power, File Number R-3398-98, February 20, 1998, p. 5.
5
“Generation” and “transmission” are sometimes referred to as “production” and
“transportation”, respectively.
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Costs attributable to reconstruction resulting from the ice storm of January 1998 will be
excluded.
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The Purpose and Structure of the Evidence
The Régie de l’énergie (the “Régie”) has initiated this proceeding to assist it in
preparing its recommendations to the Government regarding the procedure for the
determination and implementation of rates for the supply of electric power, in
accordance with article 167 of the Act.
Option
consommateurs
and
la
Fédération
nationale
des
associations
de
consommateurs du Québec (FNACQ) engaged John Todd to provide evidence that
addresses the concern that the proposal of Hydro-Québec does not establish
cost-based rates as is required by the Act.
The evidence sets out an alternative
approach that would be more consistent with the cost-based regulation methods used
elsewhere in Canada.
Mr. Todd, President of Econalysis Consulting Services, Inc., was engaged because he
has specialized in the theory and practice of government regulation, re-regulation and
de-regulation for 20 years. He has participated as an advisor or witness in over 100
proceedings before regulators including the Ontario Energy Board, the Public Utility
Board of Manitoba, the British Columbia Utilities Commission, and the Canadian
Radio-television and Telecommunications Commission addressing a wide range of
matters related to regulatory methodology as well as working within a rate-base
rate-of-return regulatory environment.7
The remainder of the evidence contains three sections. The first section discusses the
rationale for adopting cost-based rates. This section also examines the impact that
current trends in the North American electric industry – competition, restructuring and
reregulation – have on the feasibility of maintaining regulatory regimes that rely on
cost-based rates.
7
John Todd’s full curriculum vitae is available upon request.
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The second section describes procedures for developing cost-based rates for
Hydro-Québec that would be consistent with the approach used in other major
Canadian jurisdictions.
The third section describes an approach that could be utilized in Quebec for
streamlining the regulatory process and introducing efficiency incentives into the
traditional rate-base rate-of-return (“RB-ROR”) regulatory methodology.
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THE RATIONALE FOR ESTABLISHING COST-BASED RATES
The primary role of most regulators with rate-setting powers8 is to ensure that the rates
that are set for each customer, or customer class, are “just and reasonable”. A widely
accepted view of cost-based rates is that rates charged any customer or class of
customers should reflect the costs that are caused by that customer or customers
class. For this reason, the first step in setting rates is to determine the costs that each
customer of customer class has caused.
While there can be different views of what constitutes rates that are just and
reasonable, article 51 of the Act captures the concept quite well.9
51.
No tariff may impose higher rates or more onerous conditions than
are necessary to cover capital and operating costs, to maintain the
stability of the enterprise and the normal development of the electric
power production equipment and of transmission and distribution systems
or to provide the distributor a reasonable return on rate base.
The reference to rate base implies that the reasonable rates would be determined using
RB-ROR regulation. Article 49 reinforces the impression that the intention of the Act is
to ensure that rates are just and equitable from a cost-based RB-ROR perspective.
Subsection 49(1) directs the Régie to “determine the rate base of the distributor”, while
subsection 49(3) directs the Régie to “allow a reasonable return on the rate base of the
distributor”. Subsection 49(6) directs the Régie to “consider the distributor’s cost of
8
Regulators with rate-setting powers in Canada include the Canadian Radio-television
and Telecommunications Commission, the National Energy Board, the Ontario Energy
Board, the British Columbia Utilities Commission and the Public Utility Board of Manitoba,
as well as the Régie de l’énergie.
9
The intent of this section is not to provide a legal interpretation of the Act. Rather it is to
seek out guidance, from a public policy perspective, concerning the consistency of the
regulatory system envisioned by the Act with the regulatory regimes in other Canadian
jurisdictions.
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service, the varying risks according to classes of consumers, the competition between
various forms of energy and the maintenance of equity between rate classes”.
The public policy principles that are embedded in the Act appear to be highly consistent
with the public policy objectives that are reflected in the regulatory methods used in
other Canadian jurisdictions to establish cost-based rates.

Rates should be set at a level that recovers the company’s total revenue
requirement, where the revenue requirement is the minimum revenue needed by
the corporation to carry on its business and earn a return that is sufficient to
enable it to attract the capital needed to serve growing demand for its services.
This principle implies the need for the corporation to show that its expenses
have been reasonably incurred and that its capital assets are used and useful.

Rates for different customers or customer classes should be guided by the
extent to which the costs included in the corporation’s overall revenue
requirement are caused by each customers or class of customer. This principles
implies that there should be no cross-subsidization between customers or
classes of customers.

In setting rates, other factors such as competition between the various forms of
energy, differences in risks across rate classes, the quality of service and “such
economic, social and environmental concerns as have been identified by the
Government” (ss. 49(10)) should be considered, along with causal costs. This
principle recognizes that rate equity is not achieved by using cost of service
studies to set rates in a mechanistic manner.
Competition, Restructuring and Reregulation
Rate regulation is most commonly used for setting rates for naturally monopolistic firms,
including electricity and natural gas transmission and distribution companies, and
telecommunications common carriers.
In each of these industries, some of the
traditional monopolistic services have been evolving into competitive services. When
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industry restructuring occurs, as has happened in the North American electricity
industry, and some of the services of a monopoly firm are subjected to competition, the
process of setting rates becomes more difficult. There are three primary problems.

The cost of service of the incumbent monopolist may be higher than the cost of
service of competitive entrants due to technological change, differences in
corporate structure, or other factors.
If the incumbent is forced to charge
cost-based rates, it may be unable to sell its services in the market, with the
result that its investment related to those services may be stranded. It would be
more appropriate for the incumbent (i) to reduce the price at which the newly
competitive services are sold in order to reduce the size of the stranded cost and
(ii) to cease making new investment in competitive services that it cannot sell at
prices that recover their full costs.

The incumbent will have an incentive to cross-subsidize its monopoly services by
misallocating costs to its monopoly services in order to enable it (i) to operate
profitably in selling its competitive services at the competitive price, or (ii) to
underprice competitors, who lack the ability to cross-subsidize their competitive
services, thereby allowing the incumbent to maintain a dominant position in the
market.

The degree of competitiveness in different segments of the market can differ
quite significantly. Hence, competitive forces can be much stronger in relation
to services provided to some rate classes, relative to others. The incumbent,
therefore, has an incentive to engage in price discrimination among customer
classes, so as to recover a disproportionate share of fixed costs from the
customers where competitive forces are weakest. This strategy also helps to
maintain the dominant position of the incumbent.
Because of these problems, when some of the services of an incumbent are subjected
to competitive forces, while others remain monopolistic, the need to determine the cost
of service for the various services provided by the company (e.g., generation,
transmission and distribution) by customer class is not eliminated.
Hence, in the
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absence of a rigorous cost of service review, the risk that rates will not be equitable is
greater in an industry that is experiencing competitive restructuring.
Furthermore,
because the risk of anti-competitive pricing also exists, there is an even greater need to
scrutinize both the total costs of the corporation and the way in which costs are
allocated to customer classes.
In the case of Hydro-Québec, the need to review its cost of service, allocated costs and
rates is particularly high, because there is no history of regulatory scrutiny to provide
reassurance that rates have been set in accordance with cost-based rate setting
principles, rather than in accordance with strategic competitive concerns. It is necessary
to determine costs by service and rate class, so as to determine whether or not
cross-subsidies are embedded in the current rate structure.
The only situation in which industry restructuring in response to competition can result
in removing the need for rate regulation is when there is complete financial separation
of the competitive and monopoly activities through divestiture. In this circumstance,
both the incentive and the opportunity to use monopoly revenues to cross-subsidize
competitive services, or customer classes, are removed.
Provided the competitive
services are in fact subject to workable and effective competition, rate regulation may
be unnecessary.
In other circumstances, deregulation is rare, although industry restructuring does often
lead to reregulation, which is a restructuring of the regulatory processes. Reregulation
may take the form of incentive regulation or performance-based regulation, which
provides the utility with incentives that produce rewards for good results and penalties
for poor results. The third section suggests an approach by which incentive regulation
could be introduced in Québec’s regulatory process.
METHODOLOGY
HYDRO-QUÉBEC
FOR
ESTABLISHING
COST-BASED
RATES
FOR
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Hydro-Québec’s proposed method for the determination and implementation of rates
will only result in cost-based rates if the existing rates are cost-based. The proposed
methodology is designed to confirm the existing rates without undertaking a cost study
to determine whether they are in fact cost-based.
If the Régie is to make an independent determination as to whether the rates of
Hydro-Québec correspond to its reasonably incurred costs, and the recovery of its costs
from the various customers and customer classes is equitable, it will be necessary to
conduct a public review of Hydro-Québec’s costs and the methodology for determining
the cost of service of each customer and customer class, based on cost causality
principles.
In the case of a utility that has been subject to on-going regulatory scrutiny and has
demonstrated in a previous hearing that its rates are just and reasonable, it may not be
necessary to undergo a complete cost of service review if the utility is not seeking to
increase its rates.
However, Hydro-Québec has not been subject to formal regulatory hearings and has
never had to demonstrate to the Régie that its rates are just and reasonable. As such,
it cannot be simply assumed that its rates are just and reasonable.
It is therefore necessary to conduct a full review of Hydro-Québec’s costs in order to
establish a benchmark based on approved costs, even though the utility is not seeking
to increase its rates. Until the Régie conducts such a review, it will be unable to make
a determination that Hydro-Québec’s costs are reasonable. Without a public hearing
that examines Hydro’s costs, there can be no finding that all of Hydro’s costs have been
prudently incurred.
In addition, until the Régie has the opportunity to approve a cost of service study that
allocates Hydro-Québec’s costs to the different customers and customer classes, it
cannot make a finding that rates are in line with causal costs. Furthermore, it cannot
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satisfy itself that any deviations from strict causal costs are justified on other grounds
(competition, environmental grounds, other Government policy, etc.) as permitted by
the Act.
For these reasons, the Régie will have to conduct a hearing consisting of the following
elements in order to make a finding that Hydro-Québec’s rates are just and reasonable.

A public review of Hydro-Québec’s costs, including its operating and
maintenance expenses, capital expenditures, depreciation practices and capital
costs. These costs should be subject to a full prudency review, which involves
public disclosure of the cost information, responding to information requests of
interested parties and cross-examination at a public hearing.

Development of a cost of service study that allocates all costs to customers and
customer classes based on standard cost causality principles.
The cost of
service study should be subjected the same public review process as
Hydro-Québec’s costs.

A public review of the rationale of any deviations from revenue-to-cost ratios of
1.00 for all classes of customers to ensure that the deviations are acceptable.
Considerations in accepting revenue-to-cost ratios that deviate from 1.00
include: biases in the cost of service study, rate-setting principles other than
cost causality such as rate stability, as well as other factors recognized in
Section 49 of the Act.

A public review of the rate design of rates for each customer class, in light of the
functionally-classified cost of each customer or class of customer, to ensure that
the rate design minimizes intra-class inequities.
INTRODUCING EFFICIENCY INCENTIVES INTO RATE-BASE RATE-OF-RETURN
REGULATION
Subsequent to the Régie making a determination that Hydro-Québec’s costs are
prudently incurred and its rates are just and reasonable, (i.e., a benchmark has been
established), it may be appropriate for the Régie to consider introducing a regulatory
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mechanism that would reduce regulatory costs and would provide an incentive for
Hydro-Québec to operate more efficiently.
An interesting Canadian precedent is the regulatory scheme accepted by the British
Columbia Utilities Commission in 1996 for setting the rates of West Kootenay Power
(“WKP”).10 The essence of the WKP methodology is that Base Costs for 1995 were
established through a traditional RB-ROR review of its costs. Rates for 1996, 1997
and 1998 were set using a formula that established Target Costs. The Target Costs
for each year were determined by increasing the Base Costs by the rate of inflation
minus a productivity factor. The following formula determines the Target Cost.
Target =
Cost
Base
x
Cost
Driver
Base Cost
x
Cost
x
Escalator
Productivity
Improvement
Factor
where the Cost Drivers vary depending on the operating expense (e.g., for labour costs,
the Cost Driver is the number of direct customers, whereas for capitalized overhead the
Cost Driver is capital expenditures). An actual example for the 1996 calculation of the
Target Cost for Labour is as follows:
Cost Driver
Direct Customers
81,662
Base Cost
($1995)
$234
Base Cost Escalator
CPI BC (Cumulative)
1.0087
Productivity Improvement Factor (Cumulative) 0.9600
______
10
British Columbia Utilities Commission, Order Number G-77-96, July 17, 1996. A similar
scheme was approved by the BCUC in 1997 for setting the rates of BC Gas Utilities Ltd.
British Columbia Utilities Commission, Order Number G-85-97, July 23, 1997.
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$18,50511
At the end of each year, the Actual Costs are compared to the Target Costs and the
difference is shared equally between the shareholders and ratepayers. The final 1996
incentive sharing adjustment was $249,000 on Total Actual Costs of approximately $19
M.12
The sharing mechanism is subject to WKP’s attainment of performance standards for
reliability, safety, customer satisfaction and losses. In early 1998, the company was
denied its share of the 1997 variance on these grounds. The British Columbia Utilities
Commission denied WKP an $88,000 incentive sharing payment due to deterioration in
system reliability and customer satisfaction.13
After the initial three-year period of the incentive mechanism, it is expected that the
company will file an application that provides for a full rate-base rate-of-return review of
its 1998 costs to establish new Base Costs to form the basis for a similar multi-year
agreement extending into the next millennium.
The key benefits of this approach have been the streamlining of the regulatory process,
as well as productivity gains for the utility, translating into lower costs for ratepayers.
The regulatory streamlining results from the elimination of the requirement for a full
hearing each year of the three-year period. Instead, actual costs for 1996 and 1997
have been reviewed by interested parties in a one-day Annual Review, at which WKP’s
load forecast, power purchase forecast, and sharing calculation are approved. Other
issues such as capital budgets and operational issues are examined for informational
purposes. Parties have the ability to complain directly to the Commission during the
11
West Kootenay Power, Preliminary 1998 Revenue Requirements, Annual Revue
Presentations, December 3, 1997, Tab 9, p. 9.
12
Ibid, p. 28.
13
British Columbia Utilities Commission, Order Number G-5-98, January 8, 1998.
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Previous to the introduction of this scheme, a lengthy hearing into the
company’s General Rate Application, including a full review of its costs and how those
costs were allocated to customer classes, was generally required on an annual basis.
Hence, the regulatory process has been streamlined significantly.
In addition, the company has expended significant effort to achieve the productivity
gains included in the formula. This has produced benefits to ratepayers in terms of
lower operating and maintenance costs.
In the view of some parties, the primary
weakness of the WKP methodology is that it has actually reduced the utility’s incentive
to avoid overspending its capital budget. Under RB-ROR, the shareholder bears 100%
of the cost consequences of any capital budget variances (i.e., carrying costs on the
capital plus depreciation expense) in the test year, and the ratepayer bears 100% of
these cost consequences in subsequent years. Under the WKP incentive mechanism,
the company bears only 50% of the test year cost consequences of capital budget
variance, while customers continue to bear 100% of the subsequent cost consequences
of the variances.
While experience with incentive regulation mechanisms indicates that there is a need to
continue to refine current techniques, these mechanisms are likely to become
entrenched as an integral part of regulatory processes in Canada and elsewhere.
RECOMMENDATIONS
In conclusion, the Act implies that reasonable rates should be determined using
cost-based regulation, which is consistent with regulation methods used in other
Canadian jurisdictions. The industry standard for the establishment of cost-based rates
uses a cost-based regulation approach referred to as rate-base rate-of-return regulation.
In the current North American environment of industry restructuring, cost-based
regulation is more important than ever because of the risk of anti-competitive pricing.
Industry restructuring often leads to reregulation, in which incentive-based regulation
can improve traditional rate-base rate-of-return regulation by streamlining the regulatory
process and providing incentives for the utility to operate more efficiently.
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Hydro-Québec’s proposal for the determination and implementation of rates will only
result in cost-based rates if the existing rates are cost-based. However, it cannot be
assumed that the existing rates are cost-based since the utility has no history of
regulatory scrutiny and has never had to demonstrate to the Régie that its rates are just
and reasonable.
As such, there is a strong concern that the Hydro-Québec proposal
can not establish cost-based rates as required by the Act.
It is therefore necessary for the Régie to conduct a public hearing to determine that
Hydro-Québec’s rates are just and reasonable. To do so, the hearing should include
the following elements:

A public review of Hydro-Québec’s costs.

The development and public review of a cost of service study that allocates all
costs to customers and customer classes based on standard cost causality
principles.

A public review of the rationale of any deviations from revenue-to-cost ratios of
1.00 for all classes of customers.

A public review of the rate design of rates for each customer class.
Once the Régie has determined that Hydro-Québec’s costs and rates are just and
reasonable, the Régie may consider the introduction of an incentive-based regulatory
mechanism which has the benefits of streamlining the regulatory process, as well as
providing incentives for Hydro-Québec to operate more efficiently.
APPENDIX
Comparison of Decisions Since 1990
Revenue Requirement
Operating and
Cost of Capital
Maintenance
Requested
Approved
Requested
Approved
Requested
Approved
MPUB
Centra
$277,307,267
$252,038,266
$38,810,165
$38,523,236
12.9
12.5
$266,502,004
$262,708,759
$46,354,705
$44,716,305
12.97
12.45
$259,507,738
$257,965,265
$46,722,678
$46,722,678
11.81
11.46
$261,107,478
$258,092,047
$46,747,722
$44,247,722
11.56
11.21
$46,358,900
$45,458,900
10.58
10.17
Manitoba
1990 Test Year
(133/90)
Centra
Manitoba
1991 Test Year
(15/91)
Centra
Manitoba
1992 Test Year
(156/91)
Centra
Manitoba
1993 Test Year
(10/93 & 13/93)
Centra
See Note 1.
Manitoba
1994 Test Year
(8/94)
Centra
$264,477,900
$267,452,700
$48,152,300
$46,823,800
10.87
10.8
$267,400,000
$263,100,000
$49,037,000
$48,248,700
9.98
9.58
$25,766,000
$22,900,000
See Note 2.
Manitoba
1995 Test Year
(49/95 & 74/95)
Centra
Manitoba
1997 Test Year
(8/97 & 13/97)
Manitoba
Comparison of Decisions Since 1990
Revenue Requirement
Operating and
Cost of Capital
Maintenance
Requested
Approved
Requested
$26,995,000
$20,900,000
See Note 3.
Approved
Requested
Approved
Hydro
1990 Test Year
(43/90)
Manitoba
Hydro
1991 Test Year
(29/91)
OEB
Union Gas
$26,478,000
$29,232,000
$165,337,000
$164,337,000
12.16
11.86
$55,729,000
$40,471,000
$179,042,000
$178,042,000
12.23
11.82
$32,899,000
$9,692,000
$197,400,000
$186,538,000
11.27
10.97
Union Gas
Excess
Excess
$205,376,000
$201,898,000
10.88
10.54
1995 Test Year
$205,000
$1,859,3000
Union Gas
Excess
Excess
$210,909,000
$208,259,000
10.77
10.45
1996 Test Year
$108,583,000
$131,648,000
$221,195,000
$217,953,000
10.82
9.99
$57,217,600
$58,019,000
12.38
11.84
1991 Test Year
(EBRO 462)
Union Gas
1992 Test Year
(EBRO 470)
Union Gas
1993 Test Year
(EBRO 486)
(EBRO 486)
Union Gas
$42,536,000
1997 Test Year
Excess
$29,451
(EBRO
493/494)
Centra
$19,936,500
$14,030,300
1992 Test Year
(EBRO 474)
i
Comparison of Decisions Since 1990
Revenue Requirement
Operating and
Cost of Capital
Maintenance
Requested
Approved
Requested
Approved
Requested
Approved
Centra
Excess
Excess
$63,571,100
$61,615,600
11.36
11.04
1993 Test Year
$2,068,000
$10,780,700
$5,693,900
$43,072,900
$67,960,700
$65,367,900
11.34
10.81
$10,300,000
Excess
$167,900,000
$167,900,000
12.45
12.17
(EBRO 474-B;
483; 484)
Centra
1994 Test Year
(EBRO 474-B;
483; 484)
Consumers
Gas
$7,356,000
1990 Test Year
(EBRO 464)
Consumers
$35,100,000
$27,800,000
$184,600,000
$179,500,000
12.46
12.12
$32,600,000
$8,500,000
$196,800,000
$196,800,000
11.92
11.58
Consumers
Excess
Excess
$226,800,000
$223,600,000
10.59
10.18
Gas
$14,000,000
$35,400,000
$4,200,000
Excess
$236,000,000
$233,000,000
10.45
10.12
$248,000,000
$241,800,000
10.57
10.25
Gas
1991 Test Year
(EBRO 465)
(EBRO 465)
Consumers
Gas
1992 Test Year
(EBRO 473)
1994 Test Year
(EBRO 485)
Consumers
Gas
$55,000,000
1995 Test Year
(EBRO 487)
Consumers
Excess
Excess
Gas
$900,000
$24,400,000
1996 Test Year
ii
Comparison of Decisions Since 1990
Revenue Requirement
Operating and
Cost of Capital
Maintenance
Requested
Approved
Requested
Approved
Requested
Approved
$33,600,000
$1,600,000
$251,300,000
$248,100,000
10.10
9.94
$60,700,000
$20,040,000
$260,400,000
$250,000,000
9.61
9.17
See Note 5.
(EBRO 490)
Consumers
Gas
1997 Test Year
(EBRO 492)
Consumers
Gas
1998 Test Year
(EBRO 495)
BCUC
BC Gas
$99,300,000
$97,000,000
1994 & 1995
(1994)
(1994)
Test Year
$110,800,00
$101,500,00
(G-37-94)
(1995)
(1995)
BC Gas
See Note 4.
$24,448,000
$6,896,000
$133,335,000
$117,091,000
$14,278,000
$7,708,000
$137,133,000
$118,437,000
$11,984,000
$8,023,000
$141,126,000
$124,545,000
Test Year 1998
(G-85-97)
BC Gas
Test Year 1999
(G-85-97)
BC Gas
Test Year 2000
(G-85-97)
NOTES:
Based on Orders of the Manitoba Public Utilities Board, Ontario Energy Board and the British Columbia Utilities
Commission.
1. MPUB disallowed the following: municipal taxes of $421,800; O&M $900,00;denied volume adjustments downward;
denied threshold temperatures.
2. MPUB decreased rates by 0.5% for all General Consumer Category.
3. MPUB disallowed rate increase for all sectors.
4. BCUC ordered:
the Management Review Costs of $181,000 be shared by shareholders and customers; did not
accept the rationale for executive compensation package; 3 year amortization period of the final Hearing costs.
iii
Comparison of Decisions Since 1990
Revenue Requirement
Operating and
Cost of Capital
Maintenance
Requested
Approved
Requested
Approved
Requested
Approved
5. Return on Equity was set based on formula established by BCUC Decision Return on Common Equity, dated June 10,
1994, Order No.G-35-94.
iv