Report to Me Marc Laurin
Stikeman, Elliot
Attorney for
James Maclaren Industries Inc.
Régie De L’Énergie du
Québec
file R-3398-98
Comments on the Application Relating
to the Hydro Québec Proposal for
Determining the Conditions of
Establishing and Implementing Price
Rates for Supplying Electricity
Dr. Zak El-Ramly
President
ZE PowerGroup Inc.
MAY 1, 1998
TABLE OF CONTENTS
1
2
OVERVIEW ........................................................................................................................................ 2
1.1
THE NORTH AMERICAN ENERGY CONTEXT ...................................................................................... 2
1.2
REQUIREMENTS FOR A COMPETITIVE MARKET.................................................................................. 3
1.3
THE CHALLENGES FACING RÉGIE ...................................................................................................... 4
1.4
ASSESSMENT OF THE HYDRO-QUÉBEC PROPOSED SUPPLY PRICE ..................................................... 4
1.5
FOCUS OF THE TESTIMONY ................................................................................................................ 7
1.6
DEFICIENCIES IN THE HYDRO-QUÉBEC PROPOSED SUPPLY TARIFF ................................................... 7
1.7
EXPECTATIONS FROM A MONOPOLY.................................................................................................. 9
ANALYSIS AND ISSUES: ............................................................................................................... 10
2.1
THE NEED FOR CLEAR DIRECTION .................................................................................................. 10
2.2
INAPPROPRIATE FUNCTIONALIZATION AND COST ALLOCATION ....................................................... 10
2.3
IMPACT OF INAPPROPRIATE ALLOCATION ON THE SUPPLY TARIFF AND TRANSMISSION TARIFF ...... 11
2.3.1
Generation Related Transmission Assets .............................................................................. 12
2.3.2
Distribution/Transmission Interface and Allocation ............................................................ 12
2.4
FAIR HISTORICAL FUNCTIONALIZATION AND COST ALLOCATION .................................................... 13
2.5
VALUE OF PROPER FUNCTIONALIZATION......................................................................................... 14
2.6
A SOLUTION FOR QUÉBEC ............................................................................................................... 14
3
HOW THE PROPOSAL ANSWERS THE 5 QUESTIONS RAISED BY RÉGIE ..................... 16
4
APPROACHES IN OTHER JURISDICTIONS............................................................................. 20
5
4.1
BRITISH COLUMBIA UTILITIES' COMMISSION (BCUC) POSITION ON WHOLESALE ISSUES ............... 21
4.2
ALBERTA ENERGY AND UTILITIES BOARD (AEUB) POSITION ON GRTAS .................................... 23
SUMMARY AND RECOMMENDATIONS .................................................................................. 25
APPENDIX 1: OVERVIEW OF THE BRITISH COLUMBIA UTILITIES COMMISSION HEARING INTO
BC HYDRO'S APPLICATION FOR WHOLESALE TRANSMISSION SERVICE........................... 27
ADDITIONAL EXTRACTS FROM COMMISSION'S FINAL DECISION DECISIONS: ............................................. 29
APPENDIX 2: ABSTRACT FROM ALBERTA ENERGY AND UTILITIES BOARD DECISION . 31
APPENDIX 3: BIOGRAPHY OF DR. ZAK EL-RAMLY ..................................................................... 38
LIST OF PUBLICATIONS AND PRESENTATIONS ........................................................................................... 41
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Testimony of Dr. Zak El-Ramly
Comments on the Application Relating to the Hydro-Québec Proposal for
Determining the Conditions of Establishing and Implementing Tariffs for
Supplying Electricity - R-3398-98
1 Overview
Hydro-Québec refers to the context of the North American Energy Market as a driver for
its proposal. We start by defining our understanding of the context of the North
American Energy Market and its effects and demands on the regulatory process.
1.1
The North American Energy Context
1) The North American Market is moving towards competitive open access, which will
eventually lead to full retail competition. Competition will prevail over all aspects of
the business, from generation to distribution.
2) In the North American context, it is an accepted conclusion that the transmission
element of the business is expected to remain a monopoly into the immediate
future.
3) To manage the transmission monopoly requires fair and equitable transmission tariff
open to all users of the system, which is achieved through an independent operation
of the transmission system from owners of generation. Absence of the full
independence of the transmission system from generation requires the regulators to
pay special attention to cost allocation and the establishment of fair terms and
conditions.
4) A wholesale transmission tariff that provides for comparable and reciprocal access
has been the Federal Energy Regulatory Commission’s (FERC) primary focus, in its
Orders 888 and 889. FERC will not authorize a jurisdictional utility to participate
freely in the market unless it has filed with FERC an acceptable open access
application. However in insuring fair open access, FERC has stressed on the terms
and conditions of the tariff and not on the level or rates applied to the users. FERC
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relies on the local public utilities commissions (PUCs) on rate setting and cost
allocation. This has been especially true for non-jurisdictional utilities such as
Hydro-Québec and other Canadian entities.
5) In the new context of electricity the definition of a customer must be expanded to
include wholesale customers, retail customers, wheeling customers and supply and
export customers.
6) The transition from a regulated monopoly environment to a competitive environment
represents a special challenge for policy makers and regulators.
1.2
Requirements for a Competitive Market
1) To reap the benefits of competition require an even playing field be established. It is
important that the incumbent monopoly provider not be allowed to hide cost or cross
subsidize part of the operation with another.
2) It is also important for the competition to create as much transparency as possible.
Transparency of the cost is a proxy for regulation. The North American electricity
market, and the gas and oil markets before it, developed trading indices at the
outset of the introduction of competition.
3) In a competitive environment innovation is unleashed and even efficient producers,
such as Hydro-Québec power supply, become even more efficient, as their cost is
exposed, for the benefits of the ultimate consumer. This has been observed in the
Northwest where competition is making low-cost producers, such as BC Hydro and
the Bonneville Power Administration, more competitive.
4) To properly allow for the development of a fully competitive market, then, there is a
greater need to unbundle in detail and re-functionalize better than before, to ensure
fair allocation in cost as the services are broken into basic elements. Unbundling of
the cost components is required to separate the costs of generation, transmission,
distribution, ancillary services and customer services into wider range of qualities
and conditions of supply.
5) Proper unbundling, in the case of hybrid regulated/unregulated businesses, also
ensures that profits are not transferred from one part of the organization to the
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other. Specifically the regulated side should not subsidize the unregulated side at a
cost to ratepayers. This is a major concern to the FERC in the US context. The
FERC has conceded that they will not be concerned with this issue when Canadian
ratepayers are effected. They will leave the concern with Canadian regulators.
1.3
The Challenges Facing Régie
1) The Régie, in examining the Hydro-Québec proposal, needs to provide a
recommendation that meets more than the current objectives of a methodology of
developing supply tariff. The Régie also needs to allow Québec to move further
along the competitive, liberalized, energy market to meet government objectives and
the North American Energy Context.
2) The stakes that are dependent on the outcome of this Application are simply too
high to deter coherent decision making for the future beneficial outcome for all
stakeholders. It is particularly important not to impart benefits on monopoly owners
or its affiliates, which may be detrimental for competition and liberalization in the
end.
3) Many of the issues raised need detailed analysis. Conceptual agreement could be
reached and then discover that the devil is in the details. Examples are the dividing
line between transmission and either of generation or distribution.
4) We recognize that Québec is not moving to retail access at this stage. However, the
liberalization of the energy market is an ultimate objective. All reviews, proposals
and debates must keep this end objective in mind.
1.4
Assessment of the Hydro-Québec Proposed Supply Price
1) The objective and potential value of the proposed supply price rate (supply tariff) is
not clearly defined in the proposal. It seems to provide more of an administrative or
an accounting function than a useful price signal or business tool.
2) The proposed tariff is primarily the difference between the high voltage - L Tariff and
the Transmission Tariff developed to meet the FERC requirement. Differences do
not allow for examination of the components of the cost of supply. The premise, at
least from a regulatory perspective, is ineffective.
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3) Hydro-Québec's simplistic premise presumes that the L -tariff includes the supply
and transmission costs. Subtracting the transmission cost would produce the supply
cost. To accept this simplistic premise we need to assume that both the L - tariff and
the transmission rates are based on properly functionalized and fairly allocated cost
of service that is based on cost causation.
4) Clearly, it is not possible to debate the proposal in concept or abstract, as
Hydro-Québec proposes. It is the functionalization, fair allocation and the
establishment of historic cost causation (and modified use over time) that is at the
center of the debate, not the simple concept of cost. This challenge has been
demonstrated in current regulatory debates including those taking place in British
Columbia and Alberta.
5) Although the L - Tariff is presumably based on revenue requirements, typically
utilities rate settings never achieve uniform revenue to cost ratios. The L -Tariff has
not been exposed to the rigor of a public review process or disclosure typical of
North American utilities.
6) Hydro-Québec proposes to use the L -Tariff as a reference because it does not
include a distribution component. In the absence of detailed functionalization, the
definition of generation, transmission and distribution cost allocation or responsibility
is not clearly defined. The L - Tariff is a bundled inaccurate tariff.
7) Using the L - tariff will tend to propagate inaccuracies and misallocation, of the tariff
into the supply tariff, the price signals it sends and revenue collection for
Hydro-Québec.
8) Similarly, the transmission tariff was developed using the FERC format to allow
Hydro-Québec obtain the Power Marketing Authorization (PMA). The tariff met
FERC approval. However, it needs to be stressed that FERC does not review the
actual rate levels or the components of cost. FERC is only interested, as this time, in
ensuring the industry uses a standardized form during the complex transition period.
FERC does not ask for, or receive, information required to validate the
appropriateness of rate levels. Other than the actual rates ($ values), the tariff looks
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the same as BC Hydro's, West Kootenay Power's or any other utility who has
followed the FERC 888 pro forma tariff.
9) Although the application was accepted by a government decree – it has not met
stringent public review. It is within the exclusive jurisdiction of the Régie to fix or
modify the rates and conditions for transmission or supply of electricity by
Hydro-Québec (Section 31.1.)
10) Given the transmission rate level it seems that Hydro-Québec has lumped
everything that “walks, talks or looks like” transmission into the transmission rate.
This is what monopolies usually do. This is the concept attempted by BC Hydro (but
not accepted by the BC Utilities Commission as will be discussed later.) This is what
is implied in Hydro-Québec using the Act's definition of transmission as the basis for
cost allocation. There is no reason why the definition of the physical transmission
facility should be used for functionalization and allocation of cost responsibility.
11) We believe Hydro-Québec's transmission tariff may be imposing higher rates than
necessary and are onerous to IPPs and non Hydro-Québec users. The Régie under
section 51 has the mandate and responsibility to examine the issue. Hydro-Québec
in using the transmission rates to calculate the supply tariff has, effectively, invoked
the need to review the transmission rate.
12) In the Hydro-Québec situation, proper functionalization is especially important
because of the extent of the remote generation. Much of the high voltage, very long
and high cost transmission system does no more than bring generation from remote
areas to load centres. These transmission lines would never have been built if not
for connecting remote generation, in other words transmission were not built to
serve a load.
13) Hydro-Québec claims that the proposal protects its need for confidentiality
respecting the supply cost. Hydro-Québec ignores the fact that its generation is still
regulated. In a competitive environment, what is confidential is specific contracts
with specific customers. Cost is a product of regulation and loses its significance in a
competitive market.
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1.5
Focus of the Testimony
1) The focus of the remaining part of this testimony is on the importance of a proper
and detailed functionalization of assets in the development of prices and rates in the
new North American context of the energy industry. Emphasis is placed on
transmission for two basic reasons:
a) Proper functionalization and allocation of cost to the transmission function will
lead, automatically, to clearer allocation to the generation and distribution
functions. Further unbundling for the derivation of the cost of other services
becomes less controversial.
b) Transmission is the part of the system that will be used by third parties (other
than Hydro-Québec and their customers.) An inaccuracy in rates has immediate
impact on competitiveness and the bottom line.
1) Based on our experience in other jurisdictions, if the Régie is interested in an
effective regulatory process, we believe that the Régie will need to provide
Hydro-Québec with clear guidelines on the methodology for a proper cost of service
compatible with the new context. We understand this to be within the Régie's
mandate (Section 32.2).
2) At the outset, it should be emphasized that the Régie need not be constrained by
the impact of its action/decisions on Hydro-Québec's PMA or FERC.
a) Hydro Québec already has its PMA
b) The Régie is not obligated to abide by FERC rules
c) FERC defers to local Public Utilities Commissions (and Energy Boards) for
many of the issues
d) FERC defers to Canadian law
e) FERC has never withdrawn a PMA certificate
1.6
Deficiencies in the Hydro-Québec Proposed Supply Tariff
1) The Hydro-Québec proposal would not provide the elements of the supply cost to
allow the Régie to examine the viability of the rate.
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2) Given the Hydro-Québec proposal it is only possible to determine the viability of the
supply tariff if, and only if, the basis over which transmission revenue requirements,
and resulting transmission rates, and rate setting methodologies, are examined and
accepted by the Régie.
3) The Hydro-Québec transmission tariff does nothing to help the move to the
liberalization of trading energy in the future. The proposal does not offer any value in
terms of providing a price or cost signal to the consumers or in helping in the
examination of Hydro-Québec's resource mix.
4) The Hydro-Québec tariff provides itself with a subsidy of its generation resulting in
unfair competitive advantage to Hydro-Québec over other IPPs
5) The subsidy could ensure that all future generation will be provided by
Hydro-Québec without exposing it to market validation of its economic viability since
old depreciated facilities are used to average the cost of newer high cost facilities.
6) The Hydro-Québec tariff is based on a transmission rate that fails to recognize the
realities of transmission cost causation.
7) Accepting the proposal could result in an implicit approval of the transmission rates
without the benefits of public review
8) The distribution function should not be based on an artificial voltage level but rather
on an examination of the contribution of facilities to the function. HQ transmission
system uses high voltage facilities and the 44 kV dividing level is likely to deep into
transmission facilities in many areas (for example Montreal.)
9) Contributions to revenue by third party wheelers represent a very small fraction of
the total revenue requirements. Proper allocation of costs to supply, transmission
and distribution should not affect the rates currently paid by HQ customers.
10) A properly unbundled supply tariff should provide the Régie, and the public, with the
process and the parameters that Hydro-Québec can use or is using to acquire and
charge for the supply cost on behalf of its captive customers. The supply tariff
proposal is a step in the wrong direction - it makes the process more ambiguous.
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1.7
Expectations from a Monopoly
1) It is natural for the monopoly mindset to protect its regulated environment. The
Régie has the responsibility to ensure that the monopolistic interest does not
interfere with the natural development of a competitive market. Monopolies, such as
Hydro-Québec, to preserve their market dominance typically:
a) Use one function to subsidize another. Usually the monopoly function, such
as transmission or distribution, is used to subsidize the competitive function,
such as generation. The higher the cost attached to transmission, the lower
the cost of generation.
b) Use their market power to introduce barriers to entry for others. The
monopoly objective can be achieved by lumping as much of the cost to
transmission (the only monopoly left), the higher the costs the higher the
barrier to entry. Monopolies also impose unreasonable terms and conditions
on users of their system. That is why FERC insist on a pro forma like
approach to transmission rates in their Orders 888 and 889.
1) Hydro-Québec proposal, and its transmission rates, not only confirm the typical
approach of a monopoly but have also managed to hide the cost of supply
(generation). By driving its supply cost from two numbers Hydro-Québec does not
need to disclose the components of its supply portfolio or have it reviewed by an
independent agency, such as the Régie.
2) Unfortunately, for competition, the two monopolistic objectives can be achieved by
the same tool - making transmission rates as high as possible.
2
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Analysis and Issues:
1) In our view, the Supply Tariff as proposed by Hydro-Québec is not a viable option.
Major issues as outlined above need to be properly addressed.
2) Inclusions of facilities that should be clearly assigned to generation and distribution
in the transmission tariff dramatically demonstrates that Hydro-Québec's own
interest is driving transmission pricing. Left on its own Hydro-Québec will pursue
approaches that best meet its own interest as observed in other jurisdictions.
2.1
The Need for Clear Direction
1) It is a challenging role for the Régie to provide direction that recognizes the interest
of all stakeholders. Hydro-Québec may require clear guidelines on the methodology
to perform a cost of service study to properly functionalize and allocate transmission
costs.
2) In BC, the British Columbia Utilities Commission (BCUC) has been dealing with BC
Hydro's Transmission Application since 1995 (a summary of the process and the
recent BCUC decision will be discussed later.) The utility submitted several versions
of the tariff attempting to justify over-charging for transmission. The Commission
finally rendered a decision similar to the one issued 2 years ago after major energy
and resources have been spent on the regulatory process.
3) In Alberta, the Alberta Energy and Utilities Board sent the utilities back to the
drawing board to develop a more appropriate allocation of transmission assets to
generation to level the playing field for new Independent Power Producers (IPPs).
2.2
Inappropriate Functionalization and Cost Allocation
1) The transmission rates of Hydro-Québec are based on allocation of cost to
generation that does not add up to a fair distribution of remote generation
transportation costs. The Régie should require that the Generation Related
Transmission Assets (GRTAs) cost allocation be determined based on a reasonable
relative transmission capacity demands placed on the transmission by remote
generation to deliver electricity to major load centres.
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2) The only beneficiary is Hydro-Québec Power Supply when electricity is sold at other
than a cost basis i.e. when competing with generators at market prices. High
wheeling rates will directly affect IPPs ability to market electricity produced by their
own facilities.
3) If transmission cost is not affordable, the increased revenue that would be collected
through greater use of the unconstrained Hydro-Québec transmission system will be
curtailed. Both end users and transmission users suffer as a result of the failure to
collect greater revenues through more efficient pricing.
4) Obviously, all generation and transmission investments in the past were made with
a particular set of projected uses as the justification of the investment. A given
project’s projected uses determines the budget and financing support for a project,
the problem is agreeing long after the fact on the basis of original project
justifications.
5) The reallocation of generation related transmission costs to generation would not
have the effect of increasing the Hydro-Québec domestic tariffs. The delivered cost
remains the same, and the commodity price has not changed. That is,
Hydro-Québec transportation costs remain the same but costs come in on a
different basis. In one case all costs being in the form of wheeling charges and in
the second there are wheeling plus generation related allocation costs.
6) Historically the driver for proper functionalization was to provide proper revenue
requirement and allocation of costs among the various rate classes.
7) In the emerging competitive environment, functionalization is needed to also
breakdown the costs into its basic elements or functions such as generation,
transmission, distribution, ancillary services and other customer services.
2.3
Impact of Inappropriate Allocation on the Supply Tariff and Transmission
Tariff
1) At this point of the development of the market, the Régie needs to ensure that
Hydro-Québec is properly allocating costs, whenever a service is being unbundled,
and not subsidizing one function by another.
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2) Hydro-Québec has, in effect unbundled the cost of its operation by the development
of the transmission rate. Unfortunately, the process lacks documented rigor, and
was not the subject of public review.
3) It seems that Hydro-Québec simply included in the development of the transmission
revenue requirements any facility that "looked, talked or walked" like transmission,
irrespective to whether the facility provided services to the transmission function at
large.
4)
Inappropriate collection of transmission revenue and the resulting high
transmission rate has an immediate impact on the supply tariff because of how
Hydro-Québec liked that two rates in their proposal.
2.3.1
Generation Related Transmission Assets
1) Much of the high voltage transmission system in Québec was built to deliver low
cost remote generation to Québec load centres located predominately in the south
of the province.
2) Cost causation principles require that these transmission assets be assigned to the
generation function.
3) The dispute surrounding Generation Related Transmission Assets (GRTAs) does
not arise from a flaw of the concept of assigning transmission built to connect
remote generation to the generation function. The dispute is, rather, on the
technicality that in the process the GRTAs may provide transmission like supports
function.
4) A precedent of inappropriately failing to allocate associated transmission costs to
remote generation also makes for significant discomfort going into an unknown
future. Should increased demand occur, improperly allocated costs will lead to
inefficient and underutilized Québec transmission.
2.3.2
Distribution/Transmission Interface and Allocation
1) Hydro-Québec apparently used a voltage level of 44kV as the dividing line between
transmission and distribution assets. The definition is very arbitrary and does
necessarily reflect the use of transmission like facilities. For example, it is hard to
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imagine a major City like Montreal not using higher voltage facilities to distribute
power to its retail customers.
2) A proper criterion that could be used distribution assets is to define where the
perimeter of a distribution, or a municipal, company would have been. This will be
different for various distribution companies (or regions) depending on many factors.
3) The distribution/transmission cost allocation is not critical in a relative cost sense,
compared to generation related transmission. The distribution transmission interface
is, however, more complex to define as various retail loads could be served at
various voltage levels.
4) Ideally, the boundary for distribution is that of the future Distribution Company, or
Disco when retail access is implemented. It would be feasible to accept a proxy for
now until the distribution companies are defined. We believe that 44 kV is too low a
voltage to be considered as the boundary for distribution, for a system like that of
Hydro-Québec.
2.4
Fair Historical Functionalization and Cost Allocation
1) Proper functionalization should reflect historical cost causation that is the cost
associated with each facility should be assigned to the function that caused it to be
built.
2) It should ensure that the customers who are the users of the system, and who
helped built the system pay the correct costs for their system usage.
3) Furthermore, historical cost allocation will reflect an unbiased allocation of the
monopoly’s costs. Historical costs may have been allocated incorrectly; however; it
will provide the least biased cost allocation than any cost allocation or
functionalization studies performed to calculate a price tariff.
4) Proper cost studies analyze historic evidence of how the system evolved and how
project decisions were made.
5) After the facilities are correctly allocated as per historical cost allocations;
Hydro-Québec or any intervening part may identify elements, which may be
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incorrectly allocated. If the party can justify to the Régie why the facility is incorrectly
allocated, and its correct allocation, the Régie may allocate it to its correct function.
6) Given the extent of Hydro-Québec's transmission system and its high cost it is likely
that each major transmission facility will be individually evaluated. Factors such as
distance, isolation, whether the lines are radial, and whether a wholesale customer
would be likely to use them should be considered.
7) Fair and Equal treatment of all generation means that the cost of lines attaching new
generators to the system should be treated the same as the cost of attaching
existing stations.
2.5
Value of Proper Functionalization
1) Fairness - historically and prospectively.
2) Correct price signal for utilization of the resources (generation, transmission)
3) Correct price signal for location of new resources (IPPs and Industrial)
4) Ability of Régie to examine the prudence of Hydro-Québec supply resources,
especially that it constitutes the highest percentage of cost. Ability to examine the
viability of exports
5) Ability to determine potential for stranded costs or benefits
6) The supply tariff will provide one of the basic elements necessary to move to a fully
competitive market.
7) Ability to support Government Policy in the future
2.6
A Solution for Québec
1) The rate level of the supply tariff is driven by the correct cost allocation and proper
functionalization of facilities.
a) The issues associated with functionalization, cost allocation and ultimately
rate level and design are driven by complex judgment and compromise rather
than by standardized technical development.
b) These issues are being dealt with in jurisdictions throughout North America.
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c) However, the Régie can not rely on solutions developed in other jurisdictions
to set precedence, as these issues are specific to each jurisdiction and are
still evolving.
d) Each region is unique due to its regulatory history, configuration, topography
and resource mix.
e) As such, it is to be expected that each jurisdiction will have different criteria
and approaches to change.
f) What is clear is that Canada and Canadian utilities face unique issues
because of the vastness of the grid and the remoteness of the hydroelectric
generation as well as the low kW/mile consumption.
g) Hydro-Québec, with its very remote supply, is at an extreme by itself with a
very large part of its transmission specifically related to generation.
Interestingly Hydro-Québec's proposal is totally in the wrong direction by not
accounting for this fact.
3
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How the Proposal Answers the 5 Questions Raised by Régie
1. Considering the North American energy context, can the proposed model of
realignment of tariffs for supply of electricity be considered as well adapted to the
characteristics of the Québec electric industry?
No - because:
a) The proposal does not consider the unique characteristics of the Hydro-Québec
system, which necessitates careful allocation of the cost of the system
appropriately.
b) The proposal does not provide a mechanism that will facilitate the future
unbundling of the rates as the province and Hydro-Québec move to further
liberalization of the energy industry.
c) The proposal does not promote competitiveness. The high cost of transmission
deters third party users from using the system. The subsidized cost of the power
supply makes Hydro-Québec energy appear cheaper than it actually is.
1. What are the social, economical and environmental considerations that should be
taken into account with regard to the proposed model for the establishment and
implementation electricity supply tariffs?
a) Should ensure that the proposal sends the correct price signal for the optimal
use and development of the system.
b) Enhance the utilization of the Hydro-Québec system and storage system through
the development of rates that will promote additional utilization of these valuable
assets. Adherence to strict embedded costing all the time does not necessarily
promote utilization in a competitive market.
c) Prepare the consumer to exercise choice when the energy market opens up in
the future.
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d) Treating IPPs and marketers the same way Hydro-Québec treats itself. Ensuring
that the rates are fair, in their form, but also in their concepts.
e) Enhance market confidence in the provincial energy market. The higher the
degree of market confidence in Hydro-Québec tariff’s the higher the degree of
system utilization. The objective of high system utilization is to increase liquidity,
competition and wholesale trade in Québec. Additionally, an active wholesale
market will prepare the marketplace for a healthy future open retail access.
1. How does the proposed model of realignment of electricity tariffs assure the
conciliation (balance) between the public interest, the protection of consumers and
the equitable treatment of the suppliers?
a) The proposal only protects Hydro-Québec revenue and ensures that it remains
the only choice for consumers in the long run.
b) The proposal will disadvantage other suppliers, to a great extreme, by forcing
them to face an unfairly high transmission rate and compete with a low cost and
highly subsidized Hydro-Québec generation.
c) Hydro-Québec will enjoy the low cost of remote hydro generation while having
the rate payers and competing IPPs pay for the cost of the high cost
transmission system built to connect their facilities to the Québec consumers and
the export market.
1. What are the potential implications of Hydro-Québec’s proposal on the different
players and intervenors in the Québec energy market?
a) The proposal has no immediate impact on Hydro-Québec current ratepayers. By
design, their rate will not be affected. In the long run, however, the ratepayers
are disadvantaged by the absence of competition. Competition in new generation
could only serve to bring energy costs down in two ways:
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I.
Availing potential access to lower cost suppliers.
II.
Exerting pressure on Hydro-Québec to improve its operation,
reduce its cost, or accept lower rate of returns.
a) IPPs in Québec will be unable to compete with Hydro-Québec's low cost
generation that is also exempted (subsidized) from the necessary high cost of
connecting to the systems. Future IPPs have to pay for the artificially high
transmission cost to Hydro-Québec and also pay for connecting their future
facilities to the system. Importers will face similar hurdles trying to bring power
into Québec.
b) Hydro-Québec, by the nature of the design of the supply price, will not
experience first order impacts on its revenue. The artificially low supply cost may
promote Hydro-Québec to increase its export beyond levels justified by an
appropriately calculated cost.
1. What are the potential implications of Hydro-Québec proposal on the mandate of the
Board in accordance with its constitutive law?
a) Although the proposal deals with supply tariff only, the decision made by the
Régie could implicitly:
I.
accept the transmission rates established by Hydro-Québec
II.
result in inappropriate functionalization (and cost allocation) of
assets that will be difficult or impossible to reverse in the future
III.
deny Régie, and the public, a review of Hydro-Québec production
costs, management of resources; import purchase and contracts
and future resource plans, and
IV.
establish precedence that may harm the future retail access
market, when the electric industry is liberalized.
a) Correct cost allocation and functionalization is not only important to provide
the correct price signals to users of the system; but is also very important to
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send the proper cost expenditure signals to Hydro-Québec planners and the
Régie. The Hydro-Québec planners should realize the proper cost of
generation, transmission and distribution facilities.
b) The cost allocation must be broken down into enough detail for the Régie to
insure prudent cost expenditure and to correctly monitor and regulate costs.
4
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Approaches in Other Jurisdictions
1) The determination and design of equitable transmission tariffs is evolving,
particularly in the unbundled/competitive electric energy supply structure emerging
in North America.
2) Correct functionalization and cost allocation is fundamental in the creation of a fair,
just and reasonable transmission tariff.
3) Functionalization, particularly the treatment of generation related transmission
assets, is not a new issue to the deregulation forum; however it is a controversial
one. The further the generation from the load source, the larger the issue becomes.
4) Remote generation is usually associated with hydroelectric generation, the low cost
of hydroelectric generation can justify the additional high cost of high voltage
transmission to bring the output to load centers. The overall cost of production of
hydro is competitive and the issue of transmission cost was not important when the
same user paid for both the costs of generation and transmission. The issue is
critical when users of the transmission system are not necessarily the beneficiaries
from the low cost generation. The critical question becomes: is it fair to encumber
those user with the cost of that part of the transmission that was specifically built for
integrating the remote generation with the rest of the system? Or is it fairer to assign
that cost to the generators that caused that part of the system for their use?
5) Canadian utilities, notably BC Hydro, Manitoba Hydro and Hydro-Québec, are
particularly exposed to this challenge because of the vastness of the provinces and
the remoteness of generation from load center. US utilities blessed with
hydroelectric generation typically do not face the remoteness problem to the same
extent and therefore the issue is not as critical in the US.
6) The following is a summary of regulation in BC and Alberta regarding
functionalization and cost allocation of GRTAs. Although in Alberta the generation is
not remote hydro sources, the issue was still a major one.
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4.1
British Columbia Utilities' Commission (BCUC) Position on Wholesale
Issues
1) The first Wholesale Transmission Services Tariff (WTS) was filed by BC Hydro to
the British Columbia Utilities Company (“BCUC”) in November 1995. In the June
1996 the Commission accepted the BC Hydro WTS tariff, on an interim basis.
2) The Commission ordered BC Hydro to file new rates based on a study which more
precisely identifies its transmission revenue requirement. In particular, the new
transmission revenue requirement should reflect:
a) the benefits, which generation-related transmission assets provide to the
generation and transmission functions,
b)
the extent to which 138 kV and 69 kV lines provide transmission benefits,
and
c) the role of DSM with respect to transmission.
1) In the June 25,1996 Decision into BC Hydro's WTS Application the Commission
acknowledged that the cost allocation of GRTAs is a controversial one, and that cost
allocation and functionalization requires judgment since many utility costs are
incurred to achieve more than one objective. (Order G67-96)
2) Based on the evidence and argument presented with respect to the application, it
was in the Commission’s judgment that BC Hydro had not justified the
functionalization of generation-related transmission facilities to transmission. The
Commission acknowledged the technical validity of BC Hydro’s assertation that
remote generation sources may be operated to the benefit of the transmission
network. In the Commission’s judgment, BC Hydro has not demonstrated the extent
of the benefit provided by these assets. The Commission stated that they are
concerned that no costs be functionalized to transmission unless there is evidence
that the major benefit of the asset relates to transmission.
3) In the 1997 WTS Application, BC Hydro did little to remove the GRTAs from the
transmission tariff. The functionalization and appropriate costs to be included in the
transmission revenue requirement of GRTAs was again an overriding issue raised
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by the intervenors. The determination of the transmission revenue requirement, and
in particular the GRTAs, was clearly the most contentious aspect of the hearing.
4) The debate is not whether or not GRTA should be assigned to generation but rather
how much should be assigned to transmission as opposed to generation.
5) The BCUC on April 23, 1998 issued a Final Decision on the BC Hydro WTS
Application (Order G43-98):
a) The Commission decided that 100% of GRTAs in dispute should be assigned
to generation. In the April 23, 1998 Final Decision, the Commission
“recognize, but are not persuaded by, the simplicity argument set out in BC
Hydro’s favored “If it Looks, Acts, Talks, and Walks Like Transmission, Then
it Probably Is” approach”. The Commission states that BC Hydro has failed to
demonstrate that it incurred any costs in order to enjoy the system
stabilization benefits provided by its remote hydro facilities.
b) With respect to the distribution/transmission interface, the Commission
decided to allocate 100% of the 69 and 138 kV assets to transmission. The
Commission recognized that not all the 69 kV and 138 kV lines must be
functionalized to transmission solely because majorities of the lines serve a
transmission function. However, the Commission recognizes that in this
evolving market environment, the uses of a distribution/transmission line
today may be quite different from the use of the same assets tomorrow.
Expensive and detailed studies under those conditions do not seem
warranted at this time. Finally, the Commission believes that the amount of
money is comparatively small, and that accepting the known misallocations
inherent in the BC Hydro approach is unlikely to result in any meaningful
losses in system efficiency.
c) The Commission also directed BC Hydro to strengthen its Code of Conduct,
by following industry and FERC's practice. Although BC Hydro already had a
Code of Conduct approved by the Commission, the Commission felt that
"The duty of the Commission is not only to ensure that BC Hydro's intentions
are appropriate but also to ensure that the BC Hydro is aware of all situations
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in which BC Hydro must guard against both inappropriate behavior and the
appearance of inappropriate behavior."
4.2
Alberta Energy and Utilities Board (AEUB) Position on GRTAs
1) Alberta similarly has dealt with the issue of allocation transmission costs to
Company (GridCo).
2) In the recent rate hearing the Alberta Energy and Utilities generation. The
transmission system in Alberta is managed by a Grid Company the Board (AEUB)
decided to allocate part of the transmission facilities to the generators to reflect the
cost of integrating them into the grid. Since data was not readily available the Board
decided on a place holder figure to ascertain the principle o the stakeholders and
deal with the details later.
3) In the AEUB Decision U97065 concerning GridCo’s Generation Pool Access Rate
(GPA) rules (relevant section attached as Appendix 2) the Board determined:
a) Accordingly, the Board considers that, when appropriate, existing generation
can be charged for the transmission facilities used to connected it to the grid
(p.650)
b) Accordingly, the Board directs the Utilities and TA to identify and support all
facilities and their costs required to connect each generating plant to the grid
at the time of the next GRA (general rate application) (P.651)
c) Accordingly, the Board considers, for purposes of this Decision, that the
encouragement of a competitive generation market is best served by
establishing a placeholder to represent the cost of connecting existing
generation to the transmission system. (P.651)
d) Accordingly, for purposes of this Decision, the Board is prepared to deem, as
an initial placeholder, that 10% of the total transmission wire costs represents
the cost to connect generation facilities to the grid. (P.652)
e) The deemed “10%” placeholder is a temporary measure, therefore Alberta
will be faced with the issue of determining how transmission costs will be
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allocated to generation. The fact that such costs will be allocated has already
been determined.
5
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Summary and Recommendations
1) It is our conviction that the Hydro-Québec proposal is:
a) not based on accepted industry practice,
b) Hydro-Québec did not provide any information to substantiate that its
approach is superior to the industry practice,
c) is not going to promote the social, economic and environmental welfare of
Québec, and
d) does not balance the interest of the public, the protection of the consumer
and the equal treatment of the suppliers
1) We, accordingly, propose that the Régie use the following process to give the Régie
the ability to provide its advice to the government and to subsequently implement
government order and direction in a most efficient and equitable manner.
a) Not accept the proposal as submitted by Hydro-Québec. The proposal
amounts to an accounting exercise rather than a well reasoned
business/technical approach.
b) Instruct Hydro-Québec to develop a supply price tariff from its basic elements
of cost (generation-related costs, fuel costs, contracts, operation and
maintenance etc). To ensure the Régie can review each of its elements for
prudence, usefulness and fairness.
c) Instruct Hydro-Québec to functionalize and cost allocates the various facilities
based on clear cost causation. Deviation from historic cost causation should
be clearly explained and substantiated with technical studies.
d) Instruct Hydro-Québec to develop rates that meet the long-term goals based
on classical rate setting objectives. The supply rate should, as an example:
I.
collect the revenue requirement associated with supply
II.
send the correct price signal
III.
meet other policy, economic and social objectives
1) Instruct Hydro-Québec to resubmit its transmission tariff together with the supply
tariff.
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a) Hydro-Québec, correctly, invoked the need to review the transmission tariff as
the transmission tariff impacts on the supply tariff determination.
b) It is much more regulatory efficient to review the transmission tariff while
examining the supply tariff, or the methodology for setting the supply tariff.
Since they involve the same issues and analytical approach to deal with
common facilities that have to be allocated between the two functions.
c) One tariff is not of much use to Québec without the other tariff.
d) Functionalization and cost allocation issues are driven mostly by business
logic and common sense, rather than detailed technical studies.
Hydro-Québec should be instructed to develop the supply and transmission
tariff using best available information. Hydro-Québec should not be required
to finalize the revenue requirement, but use
best available
information. This will allow the Régie and stakeholders to use the best
approach and methodology with real numbers rather than in abstract without
delaying the regulatory process.
1) After the Régie makes the submission to the government based on the public
process and upon receiving the Government order, Hydro-Québec could be allowed
to resubmit more accurate revenue requirement for approval by the Régie.
2) To resolve differences in the revenue requirement estimation between
Hydro-Québec and other stakeholders, the Régie could use a consultative or an
alternative dispute resolution among stakeholders. A similar approach has been
used successfully in BC in establishing West Kootenay Power's revenue
requirement, and to some extent in Alberta.
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Appendix 1: Overview of the British Columbia Utilities Commission
Hearing into BC Hydro's Application for Wholesale Transmission
Service.
1) The BC Hydro Wholesale Transmission Services Tariff has been before the British
Columbia Utilities Commission since November 1995. The first hearing was held in
the spring of 1996, where the Commission issued a Decision dated June 25, 1996
that approved a set of WTS tariffs for BC Hydro. However, the Commission stated
that the tariffs required further analysis, and directed BC Hydro to file new rates
based on studies on GRTAs, 69/138 kV lines, and DSM which more precisely
identified its transmission revenue requirement.
2) After two more iterations to the application, BC Hydro revised the application to
conform to the Federal Energy Regulatory Commission pro forma tariff.
Subsequently a second public hearing was held into the revised Application. The
Commission released its Decision and Order on April 23, 1998.
3) The following table compares the Commission’s June 1996 and the April 23 1998
decisions to give an indication of the changes of the Commission final Decision after
2 years.
4) The main difference between the two decisions is that the Commission took a strong
position on the various issues, although resolution on the issues was no further in
the 1998 Hearing, than the 1996 Hearing.
5) This demonstrates that need for the regulators to provide clear directions to the
monopoly during the transition. The monopoly, and its employee, will instinctively try
to protect the monopoly and its historic domain from the new competitors.
June 25, 1996 Decision
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Transmission Revenue Requirement
GRTAs
BCUC judged that BCH had not justified the
Functionalize 100% of the GRTAs to
functionalization of GRTAs to transmission.
generation
Commission directed BCH to develop a new
transmission revenue requirement that reflect
the benefits provided by GRTAs to both the
generation and transmission functions
69/138 kV
BCUC accepted that certain parts of the
Functionalize 100% of the 69 and 138
69/138 kV system provide transmission
kV to transmission.
benefits, and determined that all of BCH 69
and 138 kV facilities should be functionalized
to transmission. At the same time, however,
the Commission ordered that BCH file a
study demonstrating the extent to which 69
kV and 138 kV lines provide transmission
benefits.
DSM
Commission directed BCH to file new rates
Allocate 10% of annual capitalized
which more precisely identified its TRR.
DSM costs to the TRR.
BCUC sought more evidence from BCH “to
determine what portion of its DSM costs can
be attributed to transmission”
Design of Network and Point-to-Point Transmission Rates
Network
Accept the Network Service.
Point-to-Point Service
two-part
Need to develop more efficient pricing signals
Commission approves the one-part
LRIC
than those contained in the proposed BCH
rate put forward. In addition,
rates and explicitly rejected BCH argument
Commission directs BCH to file a
that locationally efficient price signals are not
Petition for Declaratory Order with
needed until such time as transmission
FERC, asking that it formally rules on
constraints occur. Commission directed BCH
the acceptability of a two-part rate. If
to apply for new rates for WTS which reflect
that will not lead to loss of PMA, the
long-run marginal costs and locational
Commission will move to set the rates.
considerations.
Discount
Does not approve of discounting policy.
Policy
BC Hydro is required to consult with
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customers and file a new policy with
the Commission no later than October
31, 1998.
Point-to
Accept the Point-to-Point with changes
Point
as directed.
Service
Proposal
Local and
Directs BCH to work with Industrial
Bulk
Customers to bring forward a proposal
Facilities
for separating local and bulk facilities
for billing purposes and for possible
future identification by GRTAs.
Loss
Interim acceptance of average system
Compensat
losses. Directed BCH to estimate the losses
ion
for WTS based on Incremental Loss Factor,
Accept BCH average system losses.
updated on an on-going basis, and to
compensate a wholesale customer if it could
be shown that losses on the system were
reduced because of the customer’s
transactions.
Terms and Conditions
Tariff Form
Modeled after FERC mega-NOPER
Meets FERC's 888A and 889
standards
and terms
Alberta
Commission directed that there be a
Approves the auction process with a
Auction
simultaneous hourly auction for capacity on
provision in Attachment J to Tariff
the BCH Alberta Intertie when the BC/Alberta
Supplement No.30 to include a
intertie was constrained.
provision that limits the ability of one
party to reserve more than 50% of the
Total Transfer Capability available
under the first come first serve
process.
Additional Extracts from Commission's final Decision Decisions:
1) The Commission directed BC Hydro to work with Industrial Customers to bring
forward a proposal for separating local and bulk facilities for billing purposes and for
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the possible future identification of GRTAs by October 31, 1998. Commission
accepts that in the current environment in which only wholesale transmission access
is allowed and in which BC Hydro Power Supply is the only network customer and
pays the residual transmission revenue requirement, the identification of local and
bulk facilities for billing purposes is unlikely to have any significance.
2) The concern is when a real or virtual access is allowed; the more precise
identification of local and bulk facilities is required if true billing equity between BC
Hydro and its transmission is to be achieved. In addition, the Commission
recognizes that the distinction between local and bulk facilities may be relevant to
the future identification of GRTAs.
3) With respect to the relationship between BC Hydro Power Supply, Powerex, and BC
Hydro T&D the Commission required BC Hydro to comply with the current
Standards and Communication Protocols for Open Access Same Time Information
Systems as may be issued by FERC from time to time. The Commission added that
if BC Hydro believes that compliance to be unreasonable or unnecessary, they are
required to apply to the Commission for relief of compliance. The Commission
recognized that their previous direction does not adequately protect customers
against the potential for BC Hydro T&D to favour its affiliates by providing them with
preferential access to information and by engaging in discriminatory behavior.
4) The Commission further directed BC Hydro to file with the Commission a code of
Conduct for Grid-Operations and Inter-Utility Affairs, updated as required to address
concerns identified by the Intervenors, regarding transfer of personnel between the
transmission system operations and affiliates involved in the wholesale merchant
function and with regard to implementation and enforcement of the Code.
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Appendix 2: Abstract From Alberta Energy and Utilities Board Decision
The following are excerpts from Alberta Energy and Utilities Board Decision 097065,
October 31, 1997. Pages 649-652. Text emphasized in bold Italics is text excerpted by
ZE PowerGroup in the main body of this text.
To get a complete copy of this document, it can be downloaded from the Alberta
Energy and Utilities Home Page, the address and process is:

The Alberta Energy and Utilities Board, URL address: Error! Reference
source not found.

Go to “Access Docs/Find EUB Docs”

Choose “Access EUB Docs Now”

Login as a “guest”.

Press the “Projects” Button

Choose “1997 Decisions”

The EUB 079065 Decision can be found on the 3 rd Page. Press 3 on the
bottom of the page to get there. Documents are called:
Decision U97065 1996 Electric Tariff Applications – Phase 1 (Vol.1)

Decision Part U97065 1996 Electric Tariff Applications – Phase 1 (Vol.2)
5 – GridCo
5. Proposed Rates
(f) Generation Pool Access Service (GPA)
Generation Connection Charges
Board Findings
The Board considers that there are two issues related to generation integration: (1) the
appropriateness of reallocating a portion of the costs of transmission to existing
generation, and (2) the ability of the GPA rate as proposed by Gridco to send the
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correct price signals to those contemplating new generation and to those exiting
regulated service.
The Board notes that no party challenged the GPA rate as it applies to new non-utility
generation or incremental generation at existing plants. All parties agree that the
locational credits for loss reduction and deferral of new transmission included in the rate
provide incentives that should lead to optimal development of new generating resources
and deregulation of existing generation. The Board considers that application of the
GPA rate in these instances results in fair and non-discriminatory treatment of all
parties.
Page 649
With respect to the matter of identifying transmission costs to reflect the connection of
existing generation to the grid, the Board addresses this from four points of view: (1) Is
it permitted? (2) Can facilities and costs be identified? (3) Does it matter? (4) Does
IPCAA’s proposal have merit?
Is it permitted?
In responding to this fundamental question, the Board notes the following. In raising an
objection to identifying connection costs, APL appears to rely only on a consensus
reached as to how such costs were agreed to be treated, a position supported by EPI
as well. The Firm Customers contend that guidance should be taken from section
1(1)(dd) of the EU Act, which clearly defines where generation ends and transmission
begins. IPL supported its contention that identifying connection costs for existing
generation by relying on both the Consensus Agreement and the EU Act is appropriate.
Lethbridge, although opposing the identification, saw nothing in the EU Act precluding
the application of a generation integration rate payable for connecting existing
generation to the grid.
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The Board agrees with IPL that both the Consensus Agreement and the EU Act provide
support for the view that the goals of fairness and non-discriminatory practice are best
served by treating existing and new generation consistently. The Board also agrees with
Lethbridge that nothing in the EU Act precludes a transmission charge to existing
generation for integration with the grid. Accordingly, the Board considers that,
when appropriate, existing generation can be charged for the transmission
facilities used to connect it to the grid.
Can facilities and costs be identified?
The Board observes that objections of the applicants in respect of this matter are
centred on the apparent difficulty in recreating history to determine the interconnection
facilities and their costs as well as the transmission costs avoided by those facilities. On
the other hand, the Board observes that IPCAA, IPL and IPPSA believe that such an
exercise can and should be undertaken, since they contend that the connection cost is
not zero.
Although the Board agrees with the applicants that identifying the facilities and costs for
connecting existing generation to the grid may be a difficult and time-consuming
exercise, the Board considers that non-discriminatory practice dictates it be done. The
Board agrees with IPL that it is inappropriate to assign a zero toll in the absence of a
cost-of-service study verifying that the incremental costs to connect existing generation
to the system are in fact zero. While the Board expects the study to incorporate detail
sufficient to support the results, the Board recognizes that simplifying assumptions may
be needed. For example, the Board notes Gridco’s assertion that as a result of
integrated planning the location of existing generation has been optimized and
considers that this may eliminate some of the “what if” scenarios related to location
credits. Beyond the immediate need for a study to identify interconnection costs, the
Board considers that the exercise may also result in guidelines that will assist in
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determining interconnection costs for new generation. Accordingly, the Board directs
the Utilities and the TA
Page 650
to identify and support all facilities and their costs required to connect each
generating plant to the grid at the time of their next GRA (general rate
application).
Does it matter?
The Board notes that the applicants, Lethbridge and the Firm Customers take the
position that since allocating transmission costs to generation simply shifts costs from
the TA tariff to the reservation price, distribution companies are likely to be indifferent.
IPCAA and IPL go beyond the DISCO to the customer level and put forth the argument
that excessive transmission costs will impact a customer’s decisions respecting future
load and how it might be supplied. From this point of view, they stress the importance of
transmission costs being free of costs more properly charged to generation.
From the perspective of a DISCO, the Board agrees that the reallocation of costs from
transmission to regulated generation will not significantly impact the total cost paid by
DISCOs.The Board is, however, aware of the importance of properly priced
transmission in fostering a truly competitive market for generation. In this regard, the
Board agrees with POWEREX, that “(t)ransmission in the modern era is there to
facilitate competition; it’s not part of competition, and it is not to bias competition 470.”
The Board notes that BC Hydro was able to respond expeditiously to the British
Columbia Utilities Commission (BCUC) direction to allocate a portion of the
transmission system to generation.
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Based on the evidence before it, the Board believes that resolving the matter of
generation integration goes beyond the simple issue of whether costs are placed in a
transmission pot or a generation pot to one of the main goals of restructuring, that being
to encourage competition. Recognizing that the EU Act has mandated postage stamp
rates for transmission service, the Board considers it all the more important that such
rates include only those costs related to transmission. Accordingly, the Board
considers, for purposes of this Decision, that the encouragement of a competitive
generation market is best served by establishing a placeholder to represent the
cost of connecting existing generation to the transmission system. In addition to
encouraging generators, by levelling the playing field, the Board considers that lower
transmission rates might have the added benefit of retaining load that might, in the face
of excessive transmission costs, opt for self-generation.
Does IPCAA’s proposal have merit?
The Board notes that limiting the generation integration costs to switchyard facilities
only may have merit in that, no matter where located, a generating station would require
a switchyard to connect it to the grid. Further, the Board considers that, by not including
transmission lines related to existing generation, the need to speculate on location
credits is diminished. While IPCAA’s $100 million estimate of generation connection
costs lacks the depth of analysis the Board normally expects, the Board recognizes that
the Utilities were unwilling to provide the
__________
470Tr.
p.8039
Page 651
information upon which a more rigorous analysis could have been performed.
Nevertheless, the Board is concerned that the basis for IPCAA’s estimate, i.e., the
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Genesee switchyard and tap, may not be typical of generation integration facilities and
may lead to connection costs that are overstated. The Board’s reasons for this are
twofold: (1) the Genesee switchyard, presently energized at 240 kV, was designed to
operate at 500 kV, and (2) IPCAA’s estimate, being based on Genesee, ignores the
more heavily depreciated older switchyards.
While no party put forward an alternative to IPCAA’s proposal, the Board notes Gridco’s
explanation that a new incremental customer faces costs of which 90% represents the
local and bulk parts of the existing system and 10% represents incremental system
extensions. The Board also notes Gridco’s comment that “... every existing customer
who is now an embedded customer on the system was once an incremental
customer.”471 Although the Board recognizes that the
comments were made in the context of a load customer, the Board considers them
applicable to a generation customer as well, realizing that 10% might understate
generation connection charges versus those to connect load.
Accordingly, for purposes of this Decision, the Board is prepared to deem, as an
initial placeholder, that 10% of the total transmission wires costs represents the
cost to connect generation facilities to the grid. The Board recognizes that the GPA
rate cannot be reasonably applied to each generating plant to determine connection
charges and location credits and, therefore, deems that such an exercise would have
yielded GPA revenue in the amount of $43.9 million (10% x $438.6 million) if had it
been done as new incremental generation was added to the system 472. In view of the
approximation used to develop these connection costs, the Board does not consider it
necessary to refine the wire costs for the purposes of the refiling to reflect the Board’s
findings in other sections of this Decision. The Board notes that no party challenged
IPCAA’s proposal to allocate the connection costs to existing generation on the basis of
each generating unit’s MCR. The Board considers such an allocation to be appropriate
and, for the purposes of this Decision, directs Gridco to prorate the $43.9 million based
on the MCR ratings of the Utilities’ existing generating units as set out in Appendix
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GRIDCO-3. Gridco is also directed, in its refiling, to consider the generation connection
charges as an offset to the aggregate wires costs in developing its remaining
transmission rates.
With respect to their next GRAs, the Board directs the Utilities and the TA to determine
a proper estimate of generation connection costs and to provide them with their filings.
__________
471Tr.
p.7629
472Exhibit
76, Schedule 1
Page 652
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Appendix 3: Biography of Dr. Zak El-Ramly
ZE PowerGroup Inc.
1994 - Present
President
ZE PowerGroup is an international consulting firm that specializes in electricity
deregulation and competitive strategy for emerging markets. Dr. El-Ramly leads a group
of technical staff and seasoned industry associates in variety of comprehensive
projects. ZE PowerGroup is active in regulatory consulting and intervention in
jurisdictions throughout North America.
Powerex
(British Columbia Power Exchange Corporation, subsidiary of BC Hydro)
1993 - 1995
Executive Vice-president, Marketing
Responsible for sales, long-term contract negotiation and resource acquisition and for
managing daily activities. As one of the early executives credited for the development
and structuring of Powerex and its trading operation.
1990 - 1993
Vice President, Development
Responsible for the development of corporate direction to enhance the business. Led
the developed a short-term electricity market, the Power Exchange Operation (PEO).
BC Hydro
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Testimony of Dr. Zak El-Ramly
(British Columbia Hydro and Power Authority)
Dr. El-Ramly held several key managerial positions related to the management of utility
functions. He lead the development of many innovative programs and policies some of
which were modeled by other utilities in North America and abroad, most notably being
the Power Smart program, wheeling policies and an application for a rate overhaul.
1991 - 1993
Manager, Business Development, Resource Management
Development of corporate policies related to energy trade (in key areas such as rate
strategy, wheeling and exchanges with other suppliers). Negotiating complex contracts.
Responsible for the development of a BC Hydro innovative system of unbundled rates
referred to as the Industrial Rate Proposal
1989 - 1991
Manager, Policy Development, Corporate & Environmental
Development of corporate policies related to energy transactions. Led the developed of
one of the first leading edge wheeling policies in North America.
1988 - 1989
Manager, Rates & Forecasting
Personnel and resource management of Rates, Load Research and Forecasting
groups.
1985 - 1988
Marketing Manager, Residential & Commercial Energy
Market program development, program implementation and providing general technical
support for all marketing activities. Spearheaded the development of the damned side
program known internationally as Power Smart.
1983 - 1985
Projects Supervisor, Energy Management Division
1981 - 1985
Supervisor, HVAC Section Energy Conservation Division
1979 - 1981
Energy Services Systems Engineer, Energy Conservation
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1977 - 1979
HVAC Engineer, Energy Conservation Division
Carleton University
1969 - 1977
Extensive research work in the areas of flight safety, the trailing vortex problem,
computerized wind tunnel testing, acoustics, shock waves and laser measuring
techniques. Assisted in the development of the National Transportation Policy of
Canada. Various teaching and lecturing engagements.
Kuwait National Petroleum Company
1968 - 1969
Instrument engineer in a new refinery, exposed to all aspects of refinery operation
Ain Shams University, Cairo, Egypt, Mechanical Engineering Department 1964 1968
Teaching thermodynamics, heat transfer, fluid mechanics, power plants, heat engines
and HVAC
Membership
 Honorary President of the President of the Power Marketing Association (PMA) since
1995.
 Member of the New York Mercantile Exchange (NYMEX) Electricity Advisory Group
for the development of NYMEX electricity futures - 1995 - present.
 Executive member of the Western Systems Power Pool (WSPP) - 1994/1995
 Member of the Northwest Electric Light and Power Association (NELPA) -1994/1995
 Member of the Association of Professional Engineers of British Columbia (APEBC)
1997- Present
 Past President - American Society of Heating, Refrigeration, and Air Conditioning
Engineers (ASHREA), BC Chapter. Held several executive positions 1997-1990.
Regulatory
Experience
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 British Columbia Utilities Commission - BCUC:
 Policy witness for BC Hydro, Industrial Rate Proposal 1992
 Expert witness for BC Hydro - BC Hydro/WKP Long Term Power Purchase
Contract
 Intervened, participated, cross-examined and prepared final arguments in the
BC Hydro WTS hearing BC Hydro.
 Intervenor, WKP Transmission Applications - In progress
 California Public Utilities Commission (CPUC:
 Represented Powerex in the Hearing into the California restructuring.
 CPUC requested that Dr. El-Ramly also act as an expert witness.
 Federal Energy Regulatory Commission:
 Intervenor in proceedings for the approval of the ISO and Power Exchange
and IOUs’ tariff filings in California
 Represented Powerex in Filings 1994/95
 National Energy Board:
 Intervenor in the Sable Island Gas Pipeline hearing.
 Alberta Deregulation:
 Represented the Cities of Calgary, Lethbridge and Red Deer on the Advisory
Subcommittee on Section 42 and End-User Choice
 California Energy Commission (CEC):
 Represented Powerex in front of the and the Commission 1994
List of Publications and Presentations
Dr. Zak El-Ramly
1998
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 Critical elements of successful Power Contracts in a Competitive Power Market,
Annual AEE Energy Seminar, Westin Long Beach Hotel, CA, March 11
1997
 Executive Overview of the Western System Physical, Business and Regulatory
Environment Workshop, at the Third Annual Inter-Continental Power Marketing
Conference, October 7th
 Managing Trade and Risk in the Integrated Market of the Future Workshop, at the
Third Annual Inter-Continental Power Marketing Conference, October 7th
 Market Power and Affiliate Relations, at the Third Annual Inter-Continental Power
Marketing Conference, October 8th
 Managing Trade and Risk in the Western Power Market, Dow Jones Markets
Forum, WSCC Meeting, Vancouver, BC, August 7th
 Strategies for a Mixed Market, at the Western Energy Market, July 7 th
 Executive Overview of the Western System Physical and Business Environment
Workshop, at the Western Energy Market Conference, July 7 th
 Managing Trade and Risk in the Western Power Market, at the Western Energy
Market Conference, July 7th
 Transacting in an Integrated Market, at the Strategies for the Northeast Energy
Market, Montreal, April 28
 Executive Overview of the Northeast Physical and Business Environment, at the
Strategies for the Northeast Energy Market, Montreal, April 28
 Managing Trade and Risk in the Northeast Bulk Power Market, at the Strategies for
the Northeast Energy Market, Montreal, April 28
 Energy Pricing and Procurement, at the Electric Rate Derivatives Conference and
Exposition, Scottsdale, March 13-14
 Considerations Before Leaving the Utility, at the Pricing Electricity and Ancillary
Services in a Competitive Market Conference, February 24-26
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 Energy Pricing and Procurement in a Competitive Market Workshop, at the Pricing
Electricity and Ancillary Services in a Competitive Market Conference,
February 24-26
1996
 Power Pools—the Alberta Experience, at the Russia DSM Training, Vancouver
Segment, Vancouver, November 7
 Efficient Industry Restructuring: Regional Market Structures and the Alberta Power
Pool, at the Russia DSM Training, Vancouver, November 29/30
 Course facilitator, New Contractual Arrangements in a Restructured Electric Supply
Industry, Arlington, November 4-6
 Expert panel member, Transmission Divestiture and the Future, EEI Planning
Conference, Seattle, October 13-16
 Contracting for Risk Management Workshop, at The Second Annual
Inter-Continental Power Marketing Conference, Vancouver, October 7-10
 Transmission Considerations in Electricity Futures Pricing and Delivery, at The
Second Annual Inter-Continental Power Marketing Conference, Vancouver,
October 7-10
 Expert panel member, Managing the Interties Forum, The Second Annual
Inter-Continental Power Marketing Conference, Vancouver, June 7/10
 Effective Power Marketing Organizations, at the Effectively Managing a Power
Marketing Organization, Toronto, June 2/3
 Utilizing NYMEX Gas and Electric Financial Products as Risk Management
Measures Workshop, at the Power Marketing Week of Events, Toronto, June 4
 Elements of Trade/Elements of a Good Contract, at the Power Marketing Week of
Events Workshop, Toronto, June 2-7
 Alternatives to Your Utility and Considerations Before Leaving, at the Energy
Procurement in the Competitive Market Conference, Toronto, June 6/7
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 A Changing Marketplace, A Market Update, at the Operating in a Competitive
Environment: Spring 1996 Update, An Integrated Approach Conference, Salt Lake
City, March 5
1995
 Expert panel member, Utilities and the New Competitive Environment, at the
Washington, Public Utility Association's 59th Annual Meeting, Seattle, December 7
 Assessing the Pros and Cons of Refurbishing, Replacing or Upgrading Your Power
Plant, at the Middle East Power Generation Conference, Dubai, November 18-21
 Merchant Energy Markets: A Risk Management Approach, Integrated Gas and
Electric Power Marketing Conference, Houston, October 16-17
 Corporate Restructuring to Meet the Demands of the New Regime & How to
Unbundle Your Transmission Services Workshop , at the
Transmission Access and Pricing Conference, Washington, September 18/19
 Transmission Challenges in the Physical Market, at the Power Mart Conference/Exhibition, Gas daily Conference, Houston, September 7
 Successfully Negotiating Power Contracts at the Profiting from the Power Marketers
Conference, San Francisco, July 10/11
 Replacing Regulation With Market-based Rates, at the FERC's Mega NOPR,
Promoting Electric Competition Conference, Arlington , June 29/30
 The Impact of Retail Competition on Interstate Power Markets, at the Preparing for
Retail Competition in Electric Power Conference, San Francisco, June 15/16
 Successful Customer Retention: Planning Ahead for the New Market, at the Meeting
the Challenge of Competition in the Canadian Electricity Market, AIC Conferences,
Toronto, Ontario, May 24-25
 Getting Ready to Benefit from Open Access, at the National Advisory Council Spring
Meeting, BOMA, Scottsdale, May 7/8
 Power Marketing - An Opportunity or a Threat, at the Electric Utility Business
Environment Conference, Denver, March 28/29
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 Marketing Packages to Utilities, at the Integrated Gas & Electric Power Market
Conference, New York, March 27/28
 Profiling the Industry's Future & Market Driven Product and Pricing Strategies
Workshop, at the Retail Wheeling- Restructuring the Electric Industry for Competition
Conference, Chicago, March 21-24
 Power Marketing's Impact on Gas & Electricity Prices and End-User Purchases, at
the Power Fair 95, San Francisco, March 6-7
 Brand Concept and Power Marketing - The Powerex example, at the International
Utilities Executive Conference, Pheonix, February 27th-March 1st
 Transmission Challenge of the Physical Marketer: Operating Outside the Control
Area, at the Operating & Pricing Transmission Services Conference, San Diego
February 12/13
1994
 Who is the Competition in Marketing Likely to Be?, at the AIC Electric Power
Marketers Conference, New York, December 12/13
 Power Marketers Attitude Towards Transmission Access, at the Dawn of the Power
Marketer Conference, Las Vegas, October 20/21
 Strategies for Success in Power Marketing - Powerex, First Annual Meeting of the
Power Marketing Association, Washington, October 14
 Impact of Retail Wheeling on Market Dynamic, EPRI Conference Power Delivery
Group Advisory Committee Conference, Vancouver, September 21
 Efficiency and Direct Access, at the Industrial Expert Presentation on Retail
Wheeling to CPUC, San Francisco, September 15
 Canadian-US Cross-Border Power Markets and Trading Bulk Electric Power, at the
Today's Markets Trading & New Directions Conference, San Francisco, August 4
 Offering Customers More Choices and Innovative Rate Designs, at the
Re-Engineering the Electric Utility Conference, Washington, May 4/5
1993
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 Is Efficient Pricing Practical?, at the International Energy and Environmental
Congress '93, Minneapolis, August 4/5.
 Opportunities for BC IPP's: Accessing the Export Markets at the Insight Conference,
Vancouver, June 17.
 Electric Utilities' Potential Contribution to Regional Welfare and Economic
Development at the CEA Customer Services and Corporate Resources Conference,
Halifax May 16-19
9136636
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