BEFORE THE RÉGIE de L’ÉNERGIE
HYDRO-QUÉBEC
TRANSMISSION RATE
APPLICATION
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)
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CASE R-3401-98
DIRECT EVIDENCE OF
CRAIG R. ROACH, Ph.D
ON BEHALF OF
ONTARIO POWER GENERATION, INC.
FEBRUARY 7, 2001
BOSTON PACIFIC COMPANY, INC.
TABLE OF CONTENTS
I.
QUALIFICATIONS
II.
PURPOSE AND SUMMARY OF TESTIMONY
III.
TO
ENCOURAGE
NEW
ENTRANTS
INTO
THE
MARKET,
TRANSÉNERGIE SHOULD MAKE AVAILABLE TO OTHER MARKET
PARTICIPANTS THE TRANSMISSION CAPACITY ASSOCIATED WITH
HYDRO-QUÉBEC’S EXPIRING, LONG-TERM FIRM ENERGY SALES
CONTRACTS.
IV.
TRANSÉNERGIE SHOULD BE REQUIRED TO PUBLISH ON ITS OASIS
SITE TRANSPARENT, AUDITED ESTIMATES OF AVAILABLE
TRANSFER CAPABILITY (ATC).
V.
TRANSÉNERGIE SHOULD USE CONSISTENT ALLOCATION METHODS
WHEN SETTING RATES FOR LONG-TERM AND SHORT-TERM POINTTO-POINT TRANSMISSION SERVICE.
VI.
TRANSÉNERGIE SHOULD BE REQUIRED TO USE AN OPEN AUCTION
PROCESS FOR DISCOUNTING.
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BOSTON PACIFIC COMPANY, INC.
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I.
QUALIFICATIONS
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Q. Please state your name, position, and business address.
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A. My name is Craig R. Roach. I am a Principal with Boston Pacific Company, Inc. My
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business address is 1100 New York Avenue, NW, Suite 490 East, Washington, DC
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20005.
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Q. What is your educational background?
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A. I earned my Ph.D. in Economics from the University of Wisconsin and my Bachelor
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of Science degree in economics, cum laude, from John Carroll University.
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Q. Please describe your professional experience?
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A. I have twenty-five years of experience working on investments in, policies for, and
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litigation concerning the electricity and natural gas businesses. From 1975 to 1979, I
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was an economist with the U.S. Congressional Budget Office. From 1979 to 1982, I
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was a Project Manager with ICF Incorporated, an energy and environmental
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consulting firm.
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From 1983 to the present, I have worked with Boston Pacific, first in San Francisco
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and since 1987 in Washington DC. Boston Pacific is an energy consulting and
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investment services firm.
My clients include competitive (unregulated) power
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suppliers, electric and gas marketers, electric utilities, gas pipeline companies, trade
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associations, government agencies, and energy consumers.
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Q. Please describe your experience as an expert witness.
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A. I have substantial experience as an expert witness on electricity and natural gas
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issues. A complete list of my testimonies is contained in Exhibit No.1. Also shown
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therein is a list of my invited speeches and articles on issues in the electricity and
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natural gas businesses.
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I have submitted testimony to the Federal Energy Regulatory Commission (FERC) in
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ten proceedings. I also have submitted testimony, affidavits, or comments to public
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utility commissions in thirteen states as well as in arbitrations, in State Court, in
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Federal Court, and before a Congressional Subcommittee.
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Q. Does your previous testimony include issues concerning the creation of a competitive
electricity market and the potential for anti-competitive behavior?
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A. Yes. I have testified or submitted affidavits on market power issues in the electricity
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and natural gas businesses on ten occasions. I have testified or submitted affidavits in
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five merger proceedings including four at FERC: Sempra/KN Energy in 1999;
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AEP/CSW in 1999; Entergy/GSU in 1993; and SCE/SDG&E in 1989. The fifth
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merger proceeding in which I testified was the ENOVA/Pacific Enterprises merger in
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1997 before the California Public Utilities Commission.
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Beyond expert witnessing I have extensive, direct involvement in competitive
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electricity markets. For example, I have substantial experience providing financial
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advisory services for project development and asset acquisition throughout the U.S.
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and around the world.
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Q. Please describe your experience with open access transmission policy.
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A. I have extensive, longstanding experience with open access policy. For example,
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open access is often raised in my testimony as mitigation for market power; such
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issues were raised even in my first merger testimony in 1989. Beyond this expert
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witnessing, I have managed for private clients work assessing many aspects of all six
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of the operating Independent System Operators (ISOs) in the U.S. and all ten of the
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proposed Regional Transmission Organizations (RTOs).
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II. PURPOSE AND SUMMARY OF TESTIMONY
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Q. On whose behalf are you testifying?
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A. I am testifying on behalf of Ontario Power Generation, Inc. (OPG).
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Q. What is your relationship to OPG?
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A. I am an independent consultant retained by OPG to present testimony in this
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proceeding to the Régie de l’Enérgie (the Board).
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Q. What is OPG’s primary interest in this proceeding?
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A. I understand that OPG’s primary interest is assuring open access to transmission
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service for wheeling through to U.S. markets.
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Q. What is the purpose of your testimony?
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A. The purpose of my testimony is to address four issues concerning TransÉnergie’s
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proposed transmission rate application.
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Q. What is the first of the four issues you address?
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A. The first issue I address is TransÉnergie’s proposal to allow automatic renewal of
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long-term firm transmission service contracts with 60-days prior notice.
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Q. What do you recommend to the Board with respect to this issue?
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A. To encourage new entrants into the wholesale market, I recommend that the Régie
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require that the 60-day renewal provision not apply to the transmission service
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associated with all Hydro-Québec energy sales contracts in place prior to the start of
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this proceeding.
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transmission capacity would be made available on a one-time basis to all market
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participants. The automatic renewal provision would then be included as part of these
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re-sold contracts.
Thus, when these current contracts expire, the associated
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Q. What is the second of your four issues?
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A. The second issue I address concerns the calculation of available transfer (or
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transmission) capability (ATC).
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Q. What do you recommend to the Board with respect to this issue?
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A. I recommend that TransÉnergie be required to publish on its OASIS site transparent,
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audited estimates of ATCs.
To assure transparency, the Board should make
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permanent its requirement that TransÉnergie post the information on ATCs that it
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provided in response to OPG’s data requests as well as a methodology statement
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comparable to other ISOs. In addition, I recommend that the Board require an
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independent audit of TransÉnergie’s calculations each year.
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Q. What is the third of your four issues?
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A. The third issue I address is TransÉnergie’s use of different cost allocation methods
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when setting rates for long-term (annual) firm, point-to-point service, on the one
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hand, and for short-term (monthly, weekly, daily) firm and non-firm service on the
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other.
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Q. What do you recommend to the Board with respect to this issue?
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A. I recommend that TransÉnergie be required to use consistent allocation methods.
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Q. What is the fourth and final issue you address?
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A. The fourth issue I address concerns the approach to offering discounts for short-term
transmission service.
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Q. What do you recommend to the Board with respect to this issue?
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A. I recommend that TransÉnergie be required to use an approach that is transparent and
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auditable. Specifically, I recommend that TransÉnergie be required to use auctions to
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determine discount amounts.
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Q. Are there any other general points that you will bring out in your testimony?
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A. Yes. Each of the above-mentioned issues is of particular importance in the case of
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Hydro-Québec and TransÉnergie since they are only functionally unbundled. This
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situation has the potential to lead to discrimination in transmission access or the
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perception of discrimination, both of which are equally harmful to the development of
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competitive transmission markets.
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jurisdictions where electricity markets have been restructured. Ontario addressed this
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issue by requiring corporate separation of its transmission and generation businesses
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and establishing an independent electricity market operator to operate the province’s
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electricity system in a non-discriminatory manner.
This potential has been recognized in other
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In Order No. 2000, FERC emphasized the inadequacy of functional unbundling in
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developing competitive markets as a prime motivation for the formation of Regional
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Transmission Organizations. Order No. 2000 states:
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“… [W]e do conclude that opportunities for undue discrimination continue to exist
that may not be remedied adequately by functional unbundling. We further
conclude that perceptions of undue discrimination can also impede the
development of efficient and competitive electric markets.
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III. TO ENCOURAGE NEW ENTRANTS INTO THE WHOLESALE MARKET,
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TRANSÉNERGIE SHOULD MAKE AVAILABLE TO OTHER MARKET
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PARTICIPANTS THE TRANSMISSION CAPACITY ASSOCIATED WITH
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HYDRO-QUÉBEC’S EXPIRING, LONG-TERM FIRM ENERGY SALES
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CONTRACTS.
As we noted in the NOPR and Order No. 888, vertically integrated utilities have
the incentive and the opportunity to favor their generation interests over those of
their competitors. If a transmission provider’s marketing interests have favorable
access to transmission system information or receive more favorable treatment of
their transmission requests, this obviously creates a disadvantage for market
competitors.
While we have attempted to rely on functional unbundling to address our
concerns about undue discrimination, there are indications that this is difficult for
transmission providers to implement and difficult for the market and the
Commission to monitor and police. In cases in which the Commission has issued
formal orders, we have found serious concerns with functional separation and
improper information sharing with respect to at least four public utilities.
Finally, we continue to believe that perceptions of discrimination are significant
impediments to competitive markets. Efficient and competitive markets will
develop only if market participants have confidence that the system is
administered fairly. Lack of market confidence resulting from the perception of
discrimination is not mere rhetoric. It has real-world consequences for market
participants and consumers.”1
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Q. Let us begin with the first of the four issues you raise.
1
FERC Order No. 2000, p. 65-69.
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A. The first issue concerns TransÉnergie’s proposal to allow automatic renewal of
transmission service contracts with 60-days prior notice.
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Q. What is the general policy concern for this issue?
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A. The general policy concern is that, at the start of open access by any utility, a central
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question is to what extent new market participants will have the chance to actually
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secure firm transmission service. Typically, the problem is that transmission capacity
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is in short supply and the incumbent utility has been using and would like to continue
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to use most of it for its own energy sales. In other words, despite the effort to write
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and enforce all the rules to assure open access, as a practical matter, there could be
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little transmission capacity available for any new market participants.
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Q. Is this the case with Hydro-Québec?
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A. Yes in the sense that, at the beginning of open access, Hydro-Québec was the primary
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user of the transmission system and that, today, this continues to be the case.
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Q. How is this broad policy concern relevant to the proposal for automatic renewal?
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A. It is relevant in this way. If the Commission approves TransÉnergie’s proposal to
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give Hydro-Québec a right to extend its long-term firm point-to-point transmission
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service by doing no more than noticing its intent within 60 days of the expiration of
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any transmission agreement, when new competitors begin to emerge in the area,
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Hydro-Québec’s significant control of firm transmission service will, in effect, be
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perpetuated. TransÉnergie’s proposed tariff amendment reads as follows:
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2.2. Reservation Priority for Existing Firm Service Customers:
Existing firm service customers (whole-sale requirements and transmission-only,
with a contract term of one-year or more), have the right to continue to take
transmission service from the Transmission Provider when the contract expires,
rolls over or is renewed. This transmission reservation priority is independent of
whether the existing customer continues to purchase electricity from the Producer
or elects to purchase capacity and energy from another supplier. If at the end of
the contract term, the Transmission Provider’s Transmission System cannot
accommodate all of the requests for transmission service the existing firm service
customer must agree to accept a contract term at least equal to a competing
request by any new Eligible Customer and to pay the current just and reasonable
tariff, as approved by the Régie, for such service. This transmission reservation
priority for existing firm service customers is an ongoing right that may be
exercised at the end of all firm contract terms of one-year or longer under
condition that the client advise the Transmission Service Provider at least sixty
(60) days before the end of the contract. (Exhibit No.2)
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Q. Why are you concerned that the proposed amendment might perpetuate Hydro
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Québec’s control of firm transmission service?
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A. My concern is that the perpetuated control of long-term firm transmission service
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confers an unfair competitive advantage to Hydro-Québec’s generation resources.
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Specifically, my concern is that Hydro-Québec’s control of firm transmission service
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will enable it to have an advantage when selling generation into the U.S. market.
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That is, when competing with another market participant attempting to sell energy
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from or through the TransÉnergie System, Hydro-Québec should not be able to claim
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to be the only competitor with guaranteed access to firm transmission service, nor
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should it be able to claim that it has superior access.
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Q. Is this kind of renewal amendment included in other open access tariffs?
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A. Yes. I looked at transmission tariffs for the three regions in the Eastern U.S. that are
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in the most advanced stages of restructuring. I looked at the PJM Interconnection --
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the Independent System Operator (ISO) for an area covering Pennsylvania, New
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Jersey, Maryland, Delaware and the District of Columbia. I also looked at ISO New
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England and at the New York ISO. In PJM and ISO New England, a similar priority
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to that proposed by TransÉnergie is established for existing firm transmission
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customers, that is, existing transmission contracts have a renewal provision. (Exhibit
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No.3)
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However, the New York ISO has an interesting exception to this right to renew with
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notice. The New York ISOs tariff reads as follows:
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2.2. Reservation Priority For Existing Firm Service: Existing firm service
customers (wholesale requirements and transmission-only, with a contract term
extending beyond the ISO implementation date), have the right to take
Transmission Service from the ISO in accordance with the provisions of
Attachment K. This transmission reservation priority is independent of whether
the existing customer continues to purchase Capacity and Energy from a
Transmission Owner or elects to purchase Capacity and Energy from another
Supplier. At the end of the contract terms, all NYS Transmission System
capacity associated with Grandfathered Rights and/or TCCs shall be offered
for sale as TCCs in the next TCC auction facilitated by the ISO. The sale of
these TCCs shall be governed by the provisions of Attachment M. [Emphasis
Added] (Exhibit No.3)
Q. What does this added language mean?
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A. What this means is that, for transmission service associated with existing energy sales
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that were “grand fathered” at the time open access was first established, the renewal
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right does not apply. The term “grand fathered” refers to the fact that transmission
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rights were allocated to the incumbent utility to accommodate existing energy sales
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contracts that were in place before open access.
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Q. How do you recommend that the Board handle this issue?
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A. What I recommend is akin to the NYISO approach. I recommend that the 60-day
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renewal provision not apply to the transmission service associated with all Hydro-
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Québec energy sales contracts in place prior to the start of this proceeding. I tie it to
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the start of this proceeding, rather than to the start of open access, to reflect the reality
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that Hydro-Québec still is the dominant customer for transmission services.
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Thus, when these energy sales contracts expire or are terminated, the associated
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transmission capacity would be made available, on a one-time basis, to all market
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participants. The automatic 60-day renewal provision would then be included as part
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of these re-sold contracts.
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Further, I recommend that the transmission capacity associated with Hydro-Québec’s
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energy contracts be placed in an auction. An auction will make transmission rights
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available to new market participants via an open and transparent process and has the
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added benefit of assigning transmission rights to the highest value uses.
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IV. TRANSÉNERGIE SHOULD BE REQUIRED TO PUBLISH ON ITS OASIS
3
SITE
TRANSPARENT,
AUDITED
4
TRANSFER CAPABILITY (ATC).
ESTIMATES
OF
AVAILABLE
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Q. Let’s turn to your second issue.
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A. My second issue concerns the calculation of available transfer (or transmission)
8
capabilities (ATCs).
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Q. What is the general policy concern with this issue?
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A. The general policy concern is that, to achieve effective open access, all market
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participants must be put on an equal footing with respect to access to information
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about the transmission system. In particular, all market participants must have access
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to the same information about the availability of transmission capability.
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accommodate this need, the industry has come up with a common language or
16
terminology for the calculation of ATCs.
To
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Q. How are ATCs defined?
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A. In June 1996, the North American Electric Reliability Council (NERC) defined ATCs
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as follows:
ATC Definitions
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Available Transfer Capacity (ATC) is a measure of the transfer capability
remaining in the physical transmission network for further commercial activity
over and above already committed uses. Mathematically, ATC is defined as the
Total Transfer Capability (TTC) less the Transmission Reliability Margin (TRM),
less the sum of existing transmission commitments (which includes retail
customer service) and the Capacity Benefit Margin (CBM).
Total Transfer Capability (TTC) is defined as the amount of electric
power that can be transferred over the interconnected transmission
network in a reliable manner while meeting all of a specific set of defined
pre- and post-contingency system conditions.
Transmission Reliability Margin (TRM) is defined as that amount of
transmission transfer capability necessary to ensure that the interconnected
transmission network is secure under a reasonable range of uncertainties in
system conditions.
Capacity Benefit Margin (CBM) is defined as that amount of
transmission transfer capability reserved by load serving entities to ensure
access to generation from interconnected systems to meet generation
reliability requirements.2
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Q. Does NERC suggest that information about ATC calculations be made public?
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A. Yes, and further, that the methods and assumptions for ATC calculations be
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consistent across the area encompassed by any of the electric reliability regions. For
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example, in another document concerning “standards,” NERC lays out some general
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and some very specific requirements for information dissemination. One general
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statement incorporates the spirit of this requirement:
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M1. Each Region, in conjunction with its members, shall develop and document
a Regional TTC and ATC methodology. This Regional methodology shall
be available to NERC, the Regions, and the Transmission users in the
electricity markets.3
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NERC, Available Transfer Capability Definitions and Determinations (June 1996)
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Q. Does NERC suggest that any review of the ATC calculation be required?
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A. Yes. For example, in this statement, NERC suggests that the calculation be reviewed
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at least annually:
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M3. Each Region, in conjunction with its members, shall develop and implement
a procedure to review periodically (at least annually) and ensure that the
TTC and ATC calculations and resulting values of member transmission
providers comply with the Regional TTC and ATC methodology, the NERC
Planning Standards, and applicable Regional criteria and guides.
Documentation of the results of such Regional reviews shall be provided to
NERC on request.4
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Q. Did TransÉnergie live up to the letter and the spirit of these suggestions?
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A. No, not until recently. I say this because my client submitted a data request asking
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for what it believed to be the information generally provided on ATCs.
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TransÉnergie’s response was to refuse to provide it because such information was
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“strategic information from a commercial perspective.” (Exhibit No.4)
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Q. What happened next?
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A. My client contested the incomplete response from TransÉnergie and the Board
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required that the information be provided. The Board stated:
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“The Régie considers that Hydro-Québec has not demonstrated the strategic
character “from a commercial point of view” of the information requested by
OPG and it dismisses the argument put forward by Hydro-Québec that this type of
information is supplied only through the OASIS site to not give any privileged
information to any intervenor in the market. This hearing is public, all have
access to the information produced in the present case. Hydro-Québec will also
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NERC Adequacy Committee, Draft II Revised NERC Planning Standards, Measurements, and
Compliance Templates on Transfer Capability (Section I.E.1) (Total and Available Transfer Capabilities)
4
Ibid.
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be able to make public the information on its OASIS site. The information sought
is relevant and necessary.
The Régie also attaches a very great importance to transparency of the reservation
system for electricity transmission capacity. The OASIS system must also be
non-discriminatory and be perceived as such by all players in the wholesale
market.”5 (in-house translation)
Q. Did TransÉnergie comply?
A. Yes. TransÉnergie posted the answer on its OASIS site.
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Q. Do other transmission organizations provide more information on ATCs than
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TransÉnergie?
A. Yes.
Again, I looked to the information provided by the regions in which
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restructuring is most advanced. Namely, I looked at the postings concerning ATCs
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by PJM and NEPOOL. To illustrate the kind of dialogue and information provided
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by these two organizations I have attached the postings from their OASIS sites.
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(Exhibit No.5)
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Q. Why are accurate ATC calculations important to a competitive marketplace?
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A. Competitive generators must know how much transmission capability is available so
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that they know how much energy they can sell to their customers. Inaccurate ATC
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calculations raise the overall costs of buying and transmitting power, by making
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transmission appear scarce when, in fact, it is not. FERC underscored this point in its
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Decision 2000-214
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recent investigation of Midwestern and Southeastern bulk power markets in the U.S.
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The investigation of the Southeast bulk power market concluded:
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“In sum, ATC postings that are not fairly representative of actual transmission
capacity and that fluctuate for no apparent reason discourage, and raise the costs
of, buying and transmitting power in the bulk power market… . An improved
method to calculate the ATC across service areas is needed. Such an effort,
however, will not address the type of ATC posting deficiency, like the one
described above. Improved communication by utilities to market participants
regarding changes in ATC postings could allay suspicions that utilities manipulate
ATC for competitive gain.”6
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In the Midwest market assessment, FERC Staff completed an OASIS audit that found
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specific violations.
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“Another issue is that ATC is often inaccurately posted on the OASIS even if
calculated under the standard for the utility posting the ATC. Several market
participants alleged that certain transmission providers in the Midwest were not
accurately posting ATC. One market participant alleged that transmission
providers in the Midwest regularly post incorrect amounts for ATC and
documented three examples. This appears to be an issue concerning enforcement
of existing regulations concerning the posting of ATC on the OASIS.
This past summer, Commission Staff conducted an audit of all OASIS sites to
determine compliance with section 37.6 of the Commission’s regulations (18
C.F.R. § 37.6 (2000)). The audit findings were consistent with the allegations of
the market participants. For example, Staff found that one transmission provider
had no ATC records for constrained paths and that two transmission providers did
not post ATC 7 days in advance. Staff is evaluating the data collected and is
weighing follow-up options.
As a result of the lack of standardized procedures for calculating ATC and CBM,
and the inaccurate posting of ATC, market participants cannot determine what
transmission capacity is available so that they can make deals to provide energy to
their customers. This has an effect on the amount of transactions and is a limit on
liquidity.”7
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Investigation of Bulk Power Markets: Southeast Region, FERC Staff, November 1, 2000, p. 3-37.
Investigation of Bulk Power Markets: Midwest Region, FERC Staff, November 1, 2000, p. 2-37 to 2-38.
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Q. With respect to your second issue, what do you recommend to the Board?
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A. I make two recommendations to the Board with respect to my second issue. First, I
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recommend that the Board make permanent its requirement that TransÉnergie post on
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OASIS the information on ATCs that it provided in this proceeding in response to
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OPG’s data request. If it is not already provided, additional dialogue and explanation
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such as that provided by PJM and NEPOOL should be required to follow within 90
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days of the decision in this proceeding (see Exhibit No.5). In addition, TransÉnergie
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should be required to maintain an archived database of all relevant information that is
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used in the calculation of the posted ATC. This information should be kept for an
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appropriate period (e.g., one month for daily, one year for monthly, etc.) and should
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be downloadable by TransÉnergie’s customers on request.
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TransÉnergie’s customers to review and audit transactions, particularly short-term
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ones, in a timely manner.
This would enable
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My second recommendation picks up the theme of the NERC requirement for at least
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an annual review of ATC calculations. I recommend that the Board require an
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independent audit of TransÉnergie's ATC calculations each year.
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V.
TRANSÉNERGIE
SHOULD
USE
CONSISTENT
ALLOCATION
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METHODS WHEN SETTING RATES FOR LONG-TERM AND SHORT-
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TERM POINT-TO-POINT TRANSMISSION SERVICE.
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Q. Let us turn to your third issue.
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A. My third issue concerns the use of different cost allocation methods when setting
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rates for long-term and short-term point-to-point transmission service.
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Q. What is the general policy concern?
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A. My general policy concern involves TransÉnergie’s use of different (inconsistent)
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cost allocation methods for transmission services that vary only by the duration of
10
service. Any allocation method is a compromise or a judgment so it is difficult to
11
argue that one method is best. Two points have to be kept in mind when choosing
12
cost allocation methods. First, using inconsistent methods for similar services will
13
always raise a red flag; inconsistency will be said to cause bias or to be
14
discriminatory. Second, if inconsistent methods are used, a justification must be
15
given.
16
17
Q. How does this general policy concern apply to this proceeding?
18
A. It applies because TransÉnergie used inconsistent cost allocation methods to set rates
19
for long-term (annual) firm, point-to-point transmission service, on the one hand, and
20
for short-term (monthly, daily, hourly) firm and non-firm, point-to-point transmission
21
service on the other. For annual service, TransÉnergie used what it calls the “1-CP”
22
method; the letters “CP” refer to coincident peak. With the 1-CP Method, costs are
18
BOSTON PACIFIC COMPANY, INC.
1
allocated to a class of service according to that service’s contribution to the one,
2
highest system peak of the year. For short-term service, however, TransÉnergie used
3
another cost allocation method called “12-CP” in which costs are allocated based on
4
contribution to each of the twelve monthly system peaks.
5
6
Q. Just as background, does FERC favor one of these methods over the other?
7
A. Yes. In its Order 888 requiring open access tariffs, FERC reconfirmed its preference
8
for 12-CP although it said it was open to other methods.
9
10
11
12
13
14
We are reaffirming the use of a twelve monthly coincident peak (12-CP)
allocation method because we believe the majority of utilities plan their systems
to meet their twelve monthly peaks. Utilities that plan their systems to meet an
annual system peak (e.g., ConEd and Duke) are free to file another method if they
demonstrate that it reflects their transmission system in planning.8
15
Q. Does the switch in cost allocation methods make a big difference in rates?
16
A. Yes. If the 1-CP method was used consistently, the monthly rate would be set at
17
$6.27/kw-month. However, with TransÉnergie’s switch to 12-CP, the monthly rate is
18
set 28% higher at $8.02/kw-month. The following table shows the proposed rates by
19
duration of service.
20
21
22
8
FERC Order No. 888, p. 260.
19
BOSTON PACIFIC COMPANY, INC.
1
TABLE ONE9
2
3
4
PROPOSED TRANSMISSION RATES
FOR FIRM POINT-TO-POINT SERVICE
Duration
Annual ($kw-year)
Monthly ($kw-month)
Weekly ($kw-week)
Daily ($kw-day)
5
6
7
8
9
10
Rate
75.18
8.02
2.00
0.40
Consistent 1-CP*
75.18
6.27
1.57
0.31
Consistent 12-CP*
96.29
8.02
2.00
0.40
* Daily= Monthly/20
Weekly= Daily x 5
Q. Does TransÉnergie offer any justification for the use of inconsistent cost allocation
11
methods?
12
A. Yes. It appears that the justification is that a higher rate for monthly service will
13
serve as an incentive for transmission customers to buy annual service. (HQT-10,
14
Document 1, page 15) TransÉnergie gives similar rationale for its determination of
15
the daily rate, which is obtained by dividing the monthly rate by 20 days, and the
16
weekly rate, which is determined by multiplying the daily rate by 5 days.
17
18
19
20
21
22
23
24
“By using the number of working days to derive weekly, daily and hourly rates
from the monthly rate, the proposed method encourages clients to always opt for
the rate with the longest duration and, through the revenues thus generated,
contributes to reducing the residual revenue requirement to be recovered from
long-term services.”10
Q. Is this an appropriate justification?
9
Based on HQT-10, Document 1.
TransÉnergie response to Question 72.1 from the Régie.
10
20
BOSTON PACIFIC COMPANY, INC.
1
A. No, not in my view. When I think of justifications for different methods I think more
2
broadly about policy goals.
For example, FERC issued a Policy Statement on
3
transmission pricing which listed five principles:11
4
5
1. Transmission pricing must meet the traditional revenue requirement;
6
2. Transmission pricing must reflect comparability;
7
3. Transmission pricing should promote economic efficiency;
8
4. Transmission pricing should promote fairness; and
9
5. Transmission pricing should be practical.
10
11
Q. Do you think any of these goals is better served with the use of a consistent cost
12
allocation method for point-to-point service irrespective of its duration?
13
A. Yes. I think 2, 3, 4, and 5 might be better served for two reasons. First, I think
14
encouraging short-term use of a transmission system can improve economic
15
efficiency. For example, short-term use may allow fuller use of the system by filling
16
in demand during lower-demand periods. Second, I think it is important that new
17
market participants be treated comparably and fairly, and I believe at least some of
18
these new market participants may be looking primarily to short-term service. By
19
using the tariff calculation method to encourage transmission customers to purchase
20
annual service over short-term service, TransÉnergie is potentially creating a pricing
21
bias against new market participants.
11
Inquiry Concerning the Commission’s Pricing Policy for Transmission Services Provided by Public
21
BOSTON PACIFIC COMPANY, INC.
1
2
Q. Does TransÉnergie’s stated justification for inconsistent tariff calculations contradict
3
4
its justifications for other pricing policies?
A.
Yes.
In TransÉnergie’s discussion of its discounting procedures, it states “the
5
transmission provider can discount rates for each of the transmission services to
6
optimize utilization of available system capacity.”12 Optimized utilization of the
7
transmission system should be the goal of both the tariff calculation and discounting
8
methodology.
9
10
Q. Do other open access tariffs reflect a shift in cost allocation methods?
11
A. No, not for the sample I reviewed. What I found is that the short-term rates are
12
derived directly from the annual rate. For example, the monthly rate is just the annual
13
rate divided by 12. (Exhibit No.6)
14
15
Q. What do you recommend to the Board?
16
A. I recommend that TransÉnergie be required to use consistent cost allocation methods
17
when setting rates for long-term and short-term point-to-point transmission service.
18
Further, TransÉnergie’s weekly, daily and hourly rates for point-to-point service
19
should be based on the number of calendar days in the period and not business days
20
(i.e., weekly equals annual charge divided by 52; daily equals weekly charge divided
21
by 7).
Utilities Under the Federal Power Act (Policy Statement dated October 26, 1994)
22
BOSTON PACIFIC COMPANY, INC.
1
2
VI. TRANSÉNERGIE SHOULD BE REQUIRED TO USE AN OPEN AUCTION
3
PROCESS FOR DISCOUNTING.
4
5
Q. Finally, let us turn to your fourth issue.
6
A. My fourth issue concerns the approach to offering discounts for short-term
7
transmission service.
8
9
Q. Do you support the practice of providing discounts to short-term point-to-point
10
customers in specific cases defined by market conditions?
11
A. Yes, discounting short-term point-to-point service can assist in achieving the policy
12
goal of optimally utilizing the transmission system. Just as I stated in my discussion
13
of a consistent transmission tariff calculation, one of the goals of TransÉnergie’s
14
tariff practices should be the economically efficient use of the transmission grid.
15
Granting discounts enables the execution of short-term transactions that might not
16
otherwise take place. Discounting, if administered fairly, has been endorsed as a
17
valid practice by FERC in Order No. 888.
18
19
Q. Is there a general policy concern involved here?
12
HQT-10, Document 1, p. 17.
23
BOSTON PACIFIC COMPANY, INC.
1
A. Yes. The general policy concern is that, since it is only functionally unbundled from
2
a generation affiliate, TransÉnergie must not give even the appearance of using the
3
discounting process to favor its generation affiliate.
4
5
Q. Has TransÉnergie taken any steps to avoid such an appearance?
6
A. Yes. Indeed, TransÉnergie has taken the steps most often taken by others. That is, all
7
requests for discounts must be made through the OASIS site and, once accepted, the
8
details of the discounted service are posted on OASIS.13
9
10
Q. What, then, are your concerns?
11
A. Although I am not making any claim that this actually occurs, the specific concern is
12
that the granting of discounts by TransÉnergie could be tailored to an affiliate’s sales
13
opportunity, rather than overall market opportunities. The problem is that the method
14
of choosing when to accept discounts might not be transparent and auditable.
15
16
Q. What do you recommend?
17
A. While I recognize that this would be asking TransÉnergie to go beyond what most
18
other utilities have done, I recommend that TransÉnergie use an open auction process
19
to determine discount amounts.
20
discounts on various transmission paths. If the auction were over subscribed, then the
13
That is, TransÉnergie would accept bids for
HQT-10, Document 1, p. 17, Section 2.6.3.
24
BOSTON PACIFIC COMPANY, INC.
1
bidder or bidders with the lowest discount or discounts would win. An auction would
2
be more transparent and auditable, reducing possibilities for bias in the process. It
3
would also allow the market to assess the timing, path, and amount of discounts,
4
enabling a more efficient use of the transmission grid.
5
6
7
Q. Why should TransÉnergie implement auction procedures that go beyond the practices
of other utilities?
8
A. FERC’s rules on discounting were released with the open access rules of Order No.
9
888. Since then, FERC has recognized in Order No. 2000 that, even with open access
10
rules, functionally unbundled firms still present possibilities for discrimination or the
11
perception of discrimination. (See quotes in Section II.) Hydro-Québec is only
12
functionally unbundled from TransÉnergie, so the issue of transparency is more
13
important. For this reason, I suggest moving to an auction method of discounting to
14
provide the maximum transparency in the discounting process.
15
16
Q. Does this conclude your testimony?
17
A. Yes.
25
BOSTON PACIFIC COMPANY, INC.