|| Vol. Pg.668  1 RP-1999-0034 2 3 4 IN THE MATTER OF ss. 19(4), 57, 70 and 78 of the Ontario 5 Energy Board Act, 1998, S.O. 1998, c. 15, Sched. B; 6 7 8 AND IN THE MATTER OF an Ontario Energy Board 9 Staff proposed Electricity Distribution Performance 10 Based Regulation Handbook 11 12 13 B E F O R E : 14 G.A. DOMINY Presiding Member and Vice Chair 15 P. VLAHOS Member 16 S.F. ZERKER Member 17 18 19 Hearing held at: 20 2300 Yonge Street, 25th Floor, Hearing Room No. 1, 21 Toronto, Ontario on Thursday, October 7, 1999, 22 commencing at 0903 23 24 25 ORAL PRESENTATIONS 26 27 VOLUME 4 28 || Vol. Pg.669  1 APPEARANCES 2 JUDY KWIK/ Board Technical Staff 3 KEITH RITCHIE/ 4 STEPHEN MOTLUK/ 5 ROBERT WARREN Consumers' Association of 6 Canada 7 ROBERT POWER/ Hydro Mississauga, London 8 SEABRON ADAMSON/ Hydro, Oshawa PUC, Sarnia 9 ALEXANDER GRIEVE Hydro, St. Catharines Hydro, Whitby 10 Hydro, Petrolia PUC, St. Thomas PUC, 11 GPU Electric Inc./GPU Services Inc. 12 and Collingwood PUC, ENERConnect 13 JACK GIBBONS/ Pollution Probe 14 MURRAY KLIPPENSTEIN 15 PAUL FERGUSON/ Upper Canada Energy 16 PETER FAYE/ Alliance 17 DAVID WILLS 18 MARK RODGER/ Toronto Hydro 19 RICHARD ZEBROWSKI/ 20 GINNY TAM 21 RICHARD STEPHENSON Power Workers Union 22 DAVID POCH Green Energy Coalition 23 ELISABETH DEMARCO Lindsay Hydro, Flamborough 24 ANDREW ROMAN Halton Hills Hydro and the City of 25 Peterborough 26 ROBERT WRIGHT/ Federation of Ontario Cottagers 27 WENDY MOORE/ Association 28 JOHN McGEE || Vol. Pg.670  1 APPEARANCES (Cont'd) 2 ZIYAAD MIA/ Coalition of Distribution 3 DAVID FREY/ Utilities 4 NEIL SANFORD/ 5 JIM MacKENZIE 6 ROGER WHITE/ ECMI 7 RICHARD GROULX 8 TOM ADAMS/ Energy Probe 9 MICHAEL HILSON 10 STEPHEN CARTWRIGHT/ Enbridge Consumers Energy Inc. and 11 MARIKA HARE/ Enbridge Consumers Gas Inc. 12 JUDITH ALLAN 13 BILL HARPER Ontario Hydro Networks 14 KEVIN BELL Great Lakes Power 15 GERRY DUPONT Nepean Hydro 16 RICHARD BATTISTA Union Gas Limited 17 BRIAN McKERLIE Municipality of Chatham-Kent 18 MICHAEL JANIGAN Vulnerable Energy Consumers 19 Coalition 20 KEN ALLAN/ DTE/Probyn 21 DARIA BABAIE/ Sault Ste. Marie 22 CHESTER BOLLING/ 23 CLIVE HEALEY 24 MAURICE TUCCI/ Municipal Electric Association 25 HAL CLARK 26 27 28 || Vol. Pg.671  1 Toronto, Ontario 2 --- Upon resuming on Thursday, October 7, 1999, 3 at 0903 4 THE PRESIDING MEMBER: Good morning. 5 Ms Kwik, is there anything of an 6 administrative nature that needs to be done? 7 MS KWIK: No there is not, Mr. Chair. 8 Thank you. 9 THE PRESIDING MEMBER: Could I just ask a 10 clarification? 11 We have six presenters. Are we having six or 12 five or what? 13 MS KWIK: As it stands right now we haven't 14 had confirmation that Ottawa Hydro has cancelled its 15 appearance, so for now it is six. 16 THE PRESIDING MEMBER: Thank you. 17 Good morning, Mr. Roman, I believe it is your 18 group. 19 MR. ROMAN: Actually, I am with the second 20 group. 21 THE PRESIDING MEMBER: I'm sorry, I apologize. 22 I had better look at the schedule. 23 I'm wrong. It is Upper Canada Energy 24 Alliance. I'm sorry. 25 MR. WILLS: Good morning. 26 THE PRESIDING MEMBER: Good morning. 27 Would you introduce yourselves, please? Would 28 you introduce yourselves, please? || Vol. Pg.672  1 MR. WILLS: I'm sorry, I can't hear. 2 THE PRESIDING MEMBER: Would you introduce 3 yourselves, please? 4 MR. WILLS: My name is David Wills. I am the 5 General Manager of North Bay Hydro and I am here today 6 representing the Upper Canada Energy Alliance. 7 MR. FERGUSON: I am Paul Ferguson, General 8 Manager of Newmarket Hydro, also representing the Upper 9 Canada Energy Alliance. 10 THE PRESIDING MEMBER: Good morning. 11 Would you proceed, then, please? 12 PRESENTATION 13 MR. WILLS: Thank you. 14 Before I start I would like to give a little 15 bit of a preamble to comment on our group's 16 participation. 17 I think certainly at the technical hearings, 18 and possibly at these proceedings, we see a lot of 19 municipal utilities represented by lawyers -- with no 20 disrespect to Mr. Roman here -- economists or 21 consultants who speak for them on the issues raised are 22 often those who work on their client's behalf. There is 23 nothing wrong with that. We had some professional help 24 ourselves as a group. But much of what we bring are the 25 grassroots views of the people who manage Ontario's 26 municipal utilities. 27 It's interesting to observe that many of those 28 sharing those views on Ontario's distribution sector on || Vol. Pg.673  UCEA, Presentation 1 the Board's regulation task probably had little or no 2 interest in the distribution of electricity even one or 3 two years ago, or at least not in Ontario. For example, 4 to paraphrase a comment we heard from one participant at 5 the technical hearings, "Most of what I know about 6 electrical distribution I learned around the water 7 cooler." Speaking as a group who live and breathe the 8 distribution of electricity every day, we respectfully 9 suggest that there is more to it than that. 10 A number of our group have over 20 years of 11 distribution experience to contribute to this process. 12 We do not pretend to have all the answers. Quite 13 frankly, we don't think anyone does. But we hope that 14 in concert with the views of other intervenors that the 15 Board can achieve some sense of how the Board staff 16 Draft Handbook can be used as a basis which, with 17 modification, can serve the needs of the Board, MEUs and 18 Ontario's electricity customers. 19 With that, I will begin our oral presentation. 20 We are assuming that the Board will have had 21 the opportunity to review the August 1999 submission of 22 the Upper Canada Energy Alliance and this oral 23 presentation will try to summarize those views expressed 24 in the submission along with some additional comments 25 that result from the technical conference and hearings. 26 The Alliance is a group of municipal electric 27 utilities from Aurora, Georgina, Innisville, Markham, 28 Newmarket, North Bay, Orillia, Richmond Hill, Vaughan || Vol. Pg.674  UCEA, Presentation 1 and Whitchurch-Stouffville which was formed in 1998 to 2 acquire the knowledge and expertise required for power 3 procurement after industry restructuring as envisaged by 4 the Macdonald Advisory Committee. 5 Through diversity of load and geography, the 6 Alliance is using its unique load characteristics and 7 provisions of the Power Corporation Act to aggregate 8 load prior to market opening at a savings to its 9 members. 10 The Alliance agrees in principal with the 11 Board's overall direction. With members on the various 12 task forces that provided input to the PBR Rate Handbook 13 we have a good appreciation of the Board's challenge to 14 implement a regulatory regime for Ontario's municipal 15 utilities. 16 Having said that, we see what look like either 17 mistakes or errors of judgment. 18 With the time constraints that have been set 19 it appears the process is being rushed to achieve 20 arbitrary goals. We ask why. We suspect it's because 21 Ontarians were told their municipal utilities were 22 broken and inefficient and in urgent need of fixing, and 23 we believe that was an exaggeration intended to illicit 24 action from the government to form single wiresco before 25 the market opens. 26 Objective analysis by the OEB itself, or by 27 the Board staff consultants, has concluded exactly the 28 opposite. In fact, the OEB Panel at the hearing said: || Vol. Pg.675  UCEA, Presentation 1 By and large Ontario has been very efficient, has had a 2 very efficient distribution sector. 3 Since the inefficiency premise is false we 4 feel there is a latitude for the time over which 5 additional efficiencies should be implemented. 6 There is much that has to occur to comply with 7 statutory changes that have been laid out for MEUs. The 8 impact on municipal utilities and electricity customers 9 is going to be phenomenal. These changes must be 10 managed co-operatively by all parties involved. It will 11 be more difficult to do this if the transition has been 12 made unnecessarily complex. 13 We see PBR as being more suited to a stable 14 business environment but unsuited to a volatile business 15 environment and transition. We suggest that the first 16 generation of regulation be used for transition 17 activities, relevant data collection, analysis and PBR 18 designed to be followed by a first generation PBR. 19 The nature of PBR mentioned in the Macdonald 20 Report, the White Paper and the Board staff proposal 21 varies. 22 As envisaged by the Macdonald Committee PBR 23 would have been a very light-handed reporting and data 24 comparison style. While the White Paper discusses PBR 25 and proposes its use for increasing efficiency, it does 26 not specify a method. 27 The staff Handbook takes a more textbook 28 approach to regulation and makes the assumption that || Vol. Pg.676  UCEA, Presentation 1 regardless of circumstances it is necessary to start 2 tightening the regulatory thumbscrews. 3 In the final model we ask the Board to reflect 4 on our comments as context when considering the choices 5 that are available. 6 MR. FERGUSON: Our submission compares the 7 performance of Ontario's MEUs with other distributors 8 from around the world. From what we can see, Ontario's 9 MEUs could be amongst the lowest costs on a number of 10 comparators. 11 An example is OM&A expenses per customer or 12 often referred to in Ontario's industry as controllable 13 expenses. We feel they are a comprehensive indicator of 14 overall efficiency. 15 The American Public Power Association reported 16 a mean of $267 per customer for the year ending 1997. 17 The statistics gathered by the MEA for the same year 18 show a mean of $167 per customer. By this measure the 19 Ontario MEUs are significantly more efficient than their 20 American public counterparts. 21 Beyond that, the American figures are in 22 U.S. dollars and if we convert using the 67 cent 23 Canadian dollar the U.S. utilities come out spending 24 about $398 Canadian versus $167. That is about a 25 235 per cent difference. 26 When we look at American investor-owned 27 utilities the gap widens with their OM&A costs equating 28 to about $422. || Vol. Pg.677  UCEA, Presentation 1 Number of customers serviced per employee also 2 we feel is a good, broad indicator of efficiency. In 3 1997 American public power utilities reported a mean of 4 291 customers per employee for the distribution sector, 5 while in Ontario the MEUs averaged 427, again a 6 significant difference. It appears Ontario's MEUs are 7 much more efficient than their public counterparts in 8 the U.S. 9 We looked at this and we feel that we do not 10 do this at the expense of reliability. Compared to 11 Canadian, U.S., New Zealand and Australia, if there was 12 an international reliability olympics we would take 13 50 per cent of the gold medals and 50 per cent of the 14 silver. The outstanding efficiency we have has not been 15 achieved by compromising customer service. 16 If, as the White Paper notes, one of the 17 government's goals is to create a cost-effective 18 distribution sector to support Ontario's industrial 19 competitive, it would seem we already have one of the 20 best if not the best in the world. 21 MR. WILLS: In our opinion, the distribution 22 of electricity in Ontario is a success story to be 23 enhanced, not a problem to fixed. 24 We further suggest that MEUs have yet to be 25 proven greedy, inefficient monopolists who intend to 26 fleece their customers to line the pockets of a 27 shareholder because that shareholder also represents 28 customers. || Vol. Pg.678  UCEA, Presentation 1 This point was echoed by Dr. Bauer 2 representing the Consumers' Association of Canada at the 3 technical hearings when he pointed out that regulation 4 and particularly PBR was primarily designed for private 5 investor-owned utilities and only time would tell 6 whether publicly owned utilities would respond to a 7 profit motive in the same way. 8 We noted, in our submission, the difference 9 between Ontario's municipal utilities, and those 10 differences are so unique you can almost -- they are 11 almost like DNA in their characteristics. 12 The MEUs vary in size, geography, service 13 conditions, service standards, demographics, weather, 14 growth, age of plant and numerous other factors which 15 need to be understood before meaningful regulation can 16 be applied. 17 One-size-fits-all regulation with no 18 transition will match only a minority of municipal 19 utilities. 20 The Handbook states that the range of costs -- 21 which include capital and losses and, therefore, we 22 shouldn't confuse with the OM&A numbers that we just 23 quoted -- for MEUs is between $291 and $731 per customer 24 per year. A significant range and a huge disparity of 25 starting points for efficiencies. 26 On the basis of these figures alone, the 27 Alliance is concerned with the proposal to include 28 imposed productivity targets in the first phase of PBR. || Vol. Pg.679  UCEA, Presentation 1 While seemingly modest and achievable they are, 2 nevertheless, arbitrary and without justification. 3 The Alliance agrees with a rate cap as an 4 interim basis because the date of the yardstick is not 5 available. 6 For next generation, it would appear from the 7 testimony of those at the technical hearings, that 8 Ontario should be targeting the yardstick style of PBR 9 regime. 10 What's our problem with the proposed PBR? 11 Well, it seems to take the view that whatever 12 utilities are doing today is correct and all that you 13 have to do in the future is take -- that activities 14 should be frozen in time and paid for by ever-decreasing 15 rates that are assumed to cover costs. This has to be 16 wrong. The transition and implementation costs of 17 moving to the requirements of the new market, including 18 a market-based rate of return, will increase rates. 19 We have seen estimates for these increases of 20 anywhere up to 50 to 100 per cent -- that's just on 21 local costs. Therefore, it seems that the Board's 22 effort to take charge of deficiencies at a net effect 23 half of 1 per cent per year will be dwarfed by these 24 other factors. 25 It's not clear, under the Board's PBR plan, 26 how changes introduced by the transition to the new 27 market would be addressed. 28 For example, it is predictable and realistic || Vol. Pg.680  UCEA, Presentation 1 that if the Board proceeds with spot market pass through 2 the number of phone calls from customers will escalate 3 dramatically. 4 At the same time, the calls to the LDC 5 increase from customers who want advice about a 6 competitive supplier or information to assist a 7 decision -- and we are suggesting this can probably be 8 confirmed by the gas companies' experience in 9 deregulation. 10 How does the Board propose that these 11 activities will be handled? Are they Z-factors? Will 12 an increase in billing activities from customer also be 13 a Z-factor? 14 A charge for these activities would presumably 15 be seen as a barrier to switching, yet any increased 16 workload is a real cost for which there are no revenues. 17 MR. FERGUSON: In the standard supply 18 hearings, we noted definite concerns from the Board 19 about the cost of regulating alternatives to a smooth 20 spot pass through. 21 The other side of the coin is: What costs are 22 imposed on LDCs, as a result of Board policy? 23 Based on our experiences of customer reaction 24 to change, we can predict that the more the new market 25 varies from the old, the more costs could be incurred by 26 the LDC to communicate with their customers. 27 If the Board determines that the benefits of 28 immediately implementing all aspects of the new market || Vol. Pg.681  UCEA, Presentation 1 structure outweigh the aggravation and increased costs 2 to consumers, then so be it. But the Board needs to 3 seriously consider the implications of its policy 4 decisions, monitor the impacts, be accountable to 5 consumers and compensate MEUs for their increased costs. 6 In our view, we see PBR being more suited to a 7 period of sometime after transition, when accounting has 8 been standardized, when utilities can be grouped and 9 standards and levels of service are understood and have 10 been integrated into utilities' rate bases and operating 11 practices. 12 We have said that we believe the assumption of 13 urgency for PBR to be an error of judgment and that, 14 given the relatively low cost of Ontario's MEU 15 distributors, there is time to understand the impacts 16 without affecting market opening. 17 PBR is only one regulatory tool. Regulation 18 is required, but it can occur with or without PBR. 19 Delayed implementation of PBR is not the same as delayed 20 regulation. 21 On the contrary, it allows the Board the time 22 and latitude to deal with many more and varying 23 circumstances, as they warrant, using rate regulation 24 that is not overly restrictive, especially in the 25 transition stage, which will likely require many 26 individual judgments to adapt. 27 We are reminded that the successes of 28 Ontario's MEUs have been achieved with relatively simple || Vol. Pg.682  UCEA, Presentation 1 guidelines and light regulatory oversight. 2 As a matter of fact, a simple limitation on 3 ROE, with a cap and a floor, and the need for regulatory 4 approval -- or, conversely, denial of rates -- is all 5 that is required in the first phase to protect, 6 primarily, consumer interests and, also, shareholder 7 interests. 8 MR. WILLS: We observed, at the technical 9 hearings -- sorry -- the conference and hearings, that 10 the data used to calculate productivity seemed to 11 contain some errors. 12 We further noted that productivity seemed 13 highest for municipal utilities with the highest growth. 14 This is evident in the fact that the medium-sized 15 utility group had the highest productivity and a 20 per 16 cent growth over the 10-year period, while the large 17 utilities only experienced 10 per cent growth over the 18 same period and lower productivity. This is significant 19 because it means the productivity proposal is more 20 readily achievable by some municipal utilities simply 21 through the circumstance of growth, rather than 22 management. 23 Along with other intervenors, we requested the 24 opportunity to test the price and productivity index 25 data for methodology and sensitivity. But the Board, in 26 its wisdom, has elected not to make the full dataset 27 available to intervenors for analysis. 28 I'm going to try and give you an example of || Vol. Pg.683  UCEA, Presentation 1 some of those problems with productivity and IPI, and I 2 would ask you to bear with me and just use whatever 3 adjustments you have to make for -- to make the example 4 work. 5 Let's take an example of a utility that spent 6 10 million on capital in 1988 and let's just assume that 7 it spent about the same on capital in 1997, about 8 $10 million in real dollars. 9 Now, from what we can see from the Handbook, 10 if the cost of capital went down over that period, and 11 if the MEU -- even if the MEU added no customers, over 12 the period, and ignoring the other factors in the total 13 factor productivity, we understand that the methodology 14 would say that the productivity had improved. 15 I think that's simply because the cost of 16 capital went down. 17 If the MEU had added customers in the period, 18 the productivity would have been even higher. 19 So what did the MEU do with the capital? 20 In the first place, if it didn't add any 21 customers, it probably upgraded old plant. 22 Let's assume that in 1988 they upgraded 100 23 units of something. But in 1997, they upgraded only 75 24 units. The customer output measure could not 25 distinguish this difference -- which, in reality, is 26 lower productivity that would go undetected under the 27 Board staff proposal. 28 In the second case, the MEU might have added || Vol. Pg.684  UCEA, Presentation 1 only, say, 1,000 customers per, in 1988, but only 750 in 2 1997. Again, the numbers would say productivity is 3 improved; but the reality might be different. 4 With a possibility of errors and such 5 questions about the methodology for IPI and 6 productivity, we have concerns about the Board staff 7 consultants' numbers. 8 We believe that in such a climate of 9 uncertainty it would be fairer and make more sense to 10 choose a number like CPI -- as we understand has been 11 done in the majority of other jurisdictions that are 12 implementing PBR. While IPI may be a good proposal, it 13 lacks objectivity or transparency. 14 For productivity, it would seem overly 15 aggressive, in the first generation, to set it higher 16 than the average for the sample utilities until more 17 data and understanding are brought to bear on the 18 precise state of Ontario's MEUs. 19 Another suggestion is to consider a sliding 20 scale productivity of the type proposed in a yardstick 21 task force report so that the target for MEUs who are 22 already efficient would be lower than for those who 23 weren't. 24 While the data to support such a proposal is 25 no better than the data for any -- sorry -- any other 26 base data, the result seems more equitable than "one 27 size fits all". 28 MR. FERGUSON: Given that the Board has || Vol. Pg.685  UCEA, Presentation 1 committed to an initial PBR scheme, our proposal would 2 follow along the lines of a price cap, and the price cap 3 formula should follow the industry's standard at the 4 moment, commonly known as (CPI - x), plus an allowance 5 for Z-factors. 6 We also feel there should be an 7 earning/sharing mechanism that is symmetric; that is, if 8 there is a cap on the return on equity, there should 9 also be a floor, so that ratepayers and the MEUs share 10 both unexpected gains and losses. 11 We feel the productivity targets must be 12 realistic and should not penalize MEUs for past 13 efficiency improvements. Lower -cost MEUs should have 14 lower productivity factors, and vice versa. 15 Z-factors should provide incentives for 16 superior service quality and reliability and recover 17 costs that are beyond an MEU's control; for example, 18 transition costs, taxes, regulation compliance costs and 19 possible mandatory programs like rate subsidy or DSM. 20 At the technical hearings, we recommended CPI 21 over the Board staff consultants' IPI. 22 The reasons we had then, and still believe in, 23 are: first and foremost, at the moment, it is an 24 industry standard in the majority of other 25 jurisdictions, including many in North American, the 26 United Kingdom, Australia, New Zealand and Argentina; it 27 is administratively simple; it provides a proper 28 incentive because it does divorce revenue from cost -- || Vol. Pg.686  UCEA, Presentation 1 for example, it cannot be influenced by delayed cost 2 cutting -- it avoids, as David mentioned, the data and 3 the data transparency problems; it is understandable to 4 consumers and MEUs alike; it does lead to real price 5 declines in the distribution rate; and it cannot lead to 6 higher prices because under an ROE price cap excess 7 earnings must be refunded. We do have the price cap. 8 The OEB's consultants questioned CPI's 9 relevance to the input prices faced by an MEU. We 10 suggest that an MEU's costs have everything to do with 11 CPI. Our data tell us that over the last ten years 12 there was a high correlation between CPI, wage 13 escalation and Canada's long-term bond rate, the 14 benchmark for an MEU's opportunity cost of capital. 15 Labour and capital are major inputs to an MEU. 16 When negotiating for wage increases, workers justify 17 their demands against inflation, and when buying bonds 18 investors only accept a bond rate that can more than 19 offset inflation. 20 What is IPI? At the moment, it is a 21 fabricated number whose origins and make-up need to be 22 understood better by all participants to be accepted. 23 I just note on the CPI that the correlation 24 between CPI and the long-term bond rate we found to be 25 about .75, and the correlation between the industry 26 labour is higher than that, at about .80. 27 MR. WILLS: I hope this isn't too rambling for 28 you. We do jump around a little bit and drift in and || Vol. Pg.687  UCEA, Presentation 1 out of some of our arguments, state some and then come 2 back to them. But we will get to the end eventually. 3 In our submission we also talk about some 4 examples of the asymmetrical levels of service. 5 Unfortunately, we picked on OHSC, primarily because this 6 is one of the only such detailed examples in the public 7 domain. 8 In the OHSC submission to the Board for, I 9 believe, the 1999-2000 rates they detail all of the 10 activities within OM&A, and we noticed that there are 11 specific allowances for things like PCB disposal, data 12 acquisition and digital mapping. 13 We don't argue with those things, but these 14 are an example of maybe something that other utilities 15 are not doing. 16 There are some examples of things like meter 17 reading schedules where we have utilities out there that 18 are reading monthly, bimonthly, reading meters every 19 three months. These are not insignificant cost 20 implications. 21 So when we look at the cost structure for the 22 municipal utilities or OHSC, we are saying that there is 23 an asymmetric starting point for them. 24 We noted that at least one intervenor -- and I 25 am going on memory here; I think it was the Power 26 Workers Union -- advocates that municipal utilities 27 should be required to collect data electronically for 28 reporting purposes. We agree that if one company, for || Vol. Pg.688  UCEA, Presentation 1 example, Ontario Hydro Services Company, can include 2 $9.00 a customer in its rate base for its data 3 gathering, then I think you have to consider whether 4 others should be allowed to include the same kinds of 5 costs. That was the purpose of this section. 6 On the subject of service quality standards, 7 we believe that the Board should move very cautiously 8 from local accountability to central accountability that 9 cannot possibly respond to the concerns of electricity 10 customers as they have had response in the past. The 11 standards are a reasonable start, but our existing 12 standards and levels of service have evolved over many 13 years to meet the expectations of Ontario's diverse 14 communities and their needs. 15 We support the Board's proposal to talk with 16 customers to find out what really matters to them and to 17 talk with MEUs to determine whether the things that 18 matter can be practically or economically measured. 19 On the subject of communications, we believe 20 that if the Board had either field staff or maybe with 21 new technologies, some sort of other alternative 22 communications, but anyway staff with the right mandate, 23 that this could serve the Board and municipal utilities 24 well; some sort of a field representation, somebody at 25 the Board that is identified with the particular 26 municipal utility. 27 Right now, I am not sure that there is anyone 28 at the Board with a responsibility for a particular || Vol. Pg.689  UCEA, Presentation 1 municipal utility. If we have questions or need to 2 discuss our specific circumstances, who do we call? 3 Whether this is central or distributed, 4 someone has to be charged with the responsibility in the 5 municipal utility liaison. 6 With today's technology, maybe that is a web 7 based kind of thing or a question that you put on a 8 notice board or something like that. 9 Paul...? 10 MR. FERGUSON: Now you know why we are not 11 lawyers. 12 Turning now to capital contributions, our 13 submission is clear. The legislation identifies 14 municipalities as the shareholders of MEU assets and 15 indicates that the shareholder is entitled to earn a 16 return on them. 17 Setting aside exceptions, those assets have 18 been funded by one source, ratepayer funding, either 19 through periodic payments on the electric rates or a 20 one-time prepaid user fee, which we have called capital 21 contribution. 22 Assets have never been funded materially by 23 the shareholder. Therefore, to distinguish between 24 assets paid for by a ratepayer over time and assets paid 25 for in lump sum has no justification in logic or in the 26 legislation. 27 For many hydro utilities the adverse treatment 28 of contributed capital in the proposed Rate Handbook is || Vol. Pg.690  UCEA, Presentation 1 the single most important issue facing them. For some, 2 it could indeed threaten the long-term viability of the 3 business. 4 MEUs, particularly those in high-growth areas, 5 are faced with substantial capital investment 6 requirements for system expansion. The options 7 available for financing under the previous legislative 8 and regulatory structure were to simply raise rates to 9 all customers. In many cases it did conflict with the 10 beliefs of many MEUs that new development should pay for 11 itself and not be a burden to existing ratepayers. 12 We could debenture the cost and repay the debt 13 through revenues from ratepayers. This had the same 14 problems as rate increases to all customers, with the 15 complication that debentures for us were linked to 16 municipal debentures, so that a relatively insignificant 17 amount was bound by the overall repayment schedule and 18 could not be retired early if the MEUs had an objective 19 of being debt free. 20 A third option was to finance development from 21 rates by creating higher custom rates for new 22 development. While this would have achieved the goal of 23 having new development pay its way, it was complex 24 administratively and it would have required expensive 25 customization of most of the billing systems that MEUs 26 were using in the province. 27 A fourth option was to ask the developer to 28 pay the service and costs up front, and this has had || Vol. Pg.691  UCEA, Presentation 1 great appeal because it did not require any financing 2 capability from the utility. It had no impact on the 3 rate-setting process and fulfilled the objective of 4 assigning the costs of system expansion to those who 5 would benefit from them. 6 An important feature for residential customers 7 was that the cost of electrical system expansion was 8 included in the house price and could be amortized. 9 MEUs-elected commissions adopted this last 10 option because it fairly allocated the cost of growth 11 and was very efficient to administer. Since MEUs were 12 effectively not for profit co-operatives, return on 13 equity was not an issue. Had MEU commissions known that 14 such decisions would come at a future date and place 15 their utilities at a disadvantage, clearly most would 16 have decided differently. 17 With that background, we examine the Rate 18 Handbook proposal that contributed capital should be 19 treated differently than rate finance capital. 20 First and foremost, we submit that there is no 21 foundation for the proposal and economic principle. 22 Paying the capital expense for distribution system 23 expansion through a mortgage on a house, as opposed to 24 over time in the electricity rates, on the surface seems 25 no different than a consumer who buys a car with a bank 26 loan rather than through GMAC. No one would suggest 27 that General Motors forgo its profit because the 28 customer paid cash instead of taking the offered || Vol. Pg.692  UCEA, Presentation 1 financing. 2 The salient point is that the ratepayer has 3 financed all utility assets because there has never been 4 another investor in the picture. 5 So why is there a distinction drawn around the 6 time period over which he paid? 7 Secondly, we need to ask who is insisting on 8 the distinction. Certainly not the MEUs that have 9 significant contributed capital; nor, to our knowledge, 10 have any MEUs with little or no contributed capital. If 11 this were an important issue for them, we might expect 12 that they would have been vocal about it. 13 The Board's consultants, PHB, have expressed 14 the opinion that contributed capital and rate financed 15 capital should attract substantially the same rate of 16 return. Even intervenors who oppose any rate of return 17 agree that there is no distinction between rate capital 18 and contributed capital and believe they should be 19 treated as one. 20 From what we have seen, the only reason put 21 forward is the level playing field with gas. If gas 22 doesn't get a return on contributed capital, then hydro 23 utilities shouldn't either. But the gas industry never 24 did finance most of its expansion through contributed 25 capital, and it was never operated as a not for profit 26 company and has never had a commission elected by the 27 equivalent of co-operative members, and a number of 28 other dissimilarities. || Vol. Pg.693  UCEA, Presentation 1 There never was an issue of historical capital 2 contributions that hadn't been resolved or in disparity 3 of practice among gas distributors in the gas industry. 4 We are not arguing the future cap contributed capital 5 should ever return. 6 With the change in status, we accept that 7 future capital investment should receive the same 8 treatment in all utility sectors. Treating historical 9 contributed capital as proposed in the rate book has 10 some alarming consequences of which you may not be 11 aware. Some of those consequences are utilities with 12 significant amounts of contributed capital will earn 13 overall rates of return that are less than half of what 14 their rate financed counterparts earn. 15 This is a clear issue of fairness and we see 16 nothing in bill 35 that justifies discrimination on the 17 basis of artificial distinction between forms of 18 capital. 19 Historical rates of return among utilities 20 vary widely. Mandating a historical rate of return for 21 historical contributed capital will result in some 22 receiving no return on their contributed capital and 23 some receiving very close to the market based rate of 24 return simply by chance. 25 The ability to raise debt for future 26 development and expansion will be significantly impaired 27 in those utilities with a high proportion of contributed 28 capital and a low historical rate of return. Those || Vol. Pg.694  UCEA, Presentation 1 utilities may be condemned to perpetuating the 2 contributed capital dilemma because they have no 3 alternative. 4 Steady erosion of their capital base through 5 depreciation will eventually eliminate any return at all 6 and threaten the viability of the business. With all of 7 these disadvantages and no clear advantages to the rate 8 hand book proposal, we respectfully urge the Board to 9 adopt a fair and even-handed approach to capital. 10 Historical capital should be treated the same 11 regardless of the method employed to acquire it. Future 12 contributed capital can be treated in any way that the 13 Board sees fit so long as all MEUs can choose to use it 14 or not as they see fit. 15 MR. WILLS: Lastly, we touch on Appendix A of 16 the Handbook. While other intervenors have referred to 17 Appendix A, it is not clear how many have applied their 18 MEU statistics to the unbundling and evaluated the 19 results. 20 Appendix A as it stands is oversimplified in a 21 lot of significant impacts on some groups of customers. 22 At best, it illustrates the principle of unbundling, but 23 it falls into the one size fits all trap and should be 24 revised with enough flexibility to address varying 25 circumstances. 26 In our August submission, we suggested 27 unbundling using the existing box structure joint 28 transition. On reflection, this may be useful from a || Vol. Pg.695  UCEA, Presentation 1 notional point of view, but in reality it would probably 2 be beyond most billing systems and customers to adapt 3 the three rate structures within as many years. 4 A concern about the proposed rate design in 5 the Handbook is its primary reliance on a flat customer 6 charge to collect the bulk of municipal utilities' 7 imbedded costs. This will increase the bills of small 8 customers, a point that was raised several times at the 9 technical hearing. 10 An alternative as a similar approach to the 11 Rate Handbook but with the addition of an element that 12 would recover imbedded costs previously incurred in the 13 past connected load growth to achieve the twin 14 objectives of equity and efficiency along with a 15 different cost allocation. 16 In the interests of simplicity and 17 understandability for consumers, it may be advisable to 18 set the tariffs for demand and connected loads 19 separately, but rebundle them for billing purposes. 20 We urge the Board to consider the above rate 21 structures before mandating the flat customer charge 22 approach as proposed in the Handbook. 23 To conclude, the Upper Canada Energy Alliance 24 is concerned about the haste in which PBR regulation is 25 being introduced to Ontario's electricity sector and any 26 errors of judgment that could be made as a result. 27 Given the relatively high starting efficiencies of 28 Ontario's MEUs, we advocate a transition phase with || Vol. Pg.696  UCEA, Presentation 1 basic regulations such as an ROE capital clause to 2 permit a proper design for PBR to be developed with 3 adjustments to accounting and standards and levels of 4 service and improved levels of data and transparent 5 methodology for calculating indices. 6 Finally, we believe historic cost capital 7 contributions must be eligible for the same rate of 8 return as all other capital. There's no rationale to do 9 otherwise. Ratepayers alone have paid for all assets 10 and these are economic principles whenever the 11 legislation warrants two levels of capital eligible for 12 different returns. 13 That concludes our oral presentation. Thank 14 you for your patience in listening to us. 15 THE PRESIDING MEMBER: Thank you. 16 I also don't have any points of clarification 17 and then the Board will ask you questions. 18 MS KWIK: Yes, Mr. Chair. I have a couple of 19 questions. 20 In terms of service quality service standards, 21 you say that the Board should move very cautiously from 22 local accountability to central accountability. Are you 23 suggesting then that if the Board sets performance 24 standards for service quality there would no longer be 25 local accountability, that you would not take 26 accountability for service quality if the Board set 27 standards for it? 28 MR. WILLS: I think there would be local || Vol. Pg.697  UCEA 1 accountability, but I see -- I think that with a move to 2 central accountability there has to be certainly a 3 relationship with local boards. I think the very nature 4 of performance based regulation and the transfer or even 5 the sense of transfer to a central accountability may 6 create an environment where the local boards -- they may 7 well not be fully accountable for service quality 8 standards. 9 You can simply go to the lowest common 10 denominator. You know, once get into that kind of 11 thing, you drive it down to the lowest common 12 denominator to cut costs. 13 MS KWIK: Okay. Thank you. 14 I have another question. That's on the rate 15 designs going into the transition period. Could you 16 elaborate on your suggestion of recovering imbedded 17 costs previously incurred to meet past connected load 18 growth? 19 MR. WILLS: We have a paper on that that we 20 can submit. I actually had it in the oral presentation 21 at one time and then I took it out because it was quite 22 detailed and it really wasn't the kind of thing that 23 translated. 24 Just to cover off the suggestion, it was a 25 suggestion of a per kilowatt charge on demand for 26 previous highest demand and a per kilowatt hour charge 27 based on previous highest level of consumption for 28 non-demand metered customers, but we can submit the || Vol. Pg.698  UCEA 1 suggestion. 2 MS KWIK: That would be helpful if you would 3 include it in your final submission if you choose to do 4 that. 5 MR. WILLS: We will do that. 6 MS KWIK: Thank you. 7 That's all, Mr. Chair. 8 THE PRESIDING MEMBER: Thank you, Ms Kwik. 9 Mr. Vlahos. 10 MEMBER VLAHOS: Thank you, Mr. Chair. 11 Gentlemen, good morning. 12 I did have two or three questions. First I 13 want to understand the setup of your submission. You 14 start with the notion there was nothing broken to fixed 15 in the MEUs. I take those points. 16 You are not suggesting that the issue here is 17 to rewrite the Act. I don't think that's what you are 18 after. 19 MR. WILLS: No, it is not. 20 MEMBER VLAHOS: Rather, the points are raised 21 for the Board to consider those circumstances going 22 forward. That's the intent of that strong presentation 23 of the excellent service provided by the MEUs in the 24 past and the relatively long course of providing that 25 service. 26 MR. WILLS: That's correct, yes. 27 MEMBER VLAHOS: So the message for the Board 28 is to consider all those things and pay specific || Vol. Pg.699  UCEA 1 attention to your specific recommendations in fixing, as 2 you see them, fixing some of the deficiencies in the 3 Rate Handbook. Those would appear on page 5 of the 4 submission. You can turn to those, please. 5 MR. FERGUSON: Yes, sir. I think in context, 6 yes, going forward. What we are suggesting is a 7 cautious approach initially and look at some different 8 perspectives of the Handbook so that we can improve on 9 where we are today and not run any risk of degrading 10 either service or financial performance for the 11 ratepayers. 12 MEMBER VLAHOS: Okay. Before we get to the 13 discussion of those, Mr. Ferguson, I was interested in 14 the statement or suggestion that the first generation 15 PBRs should be used for transition activities such as 16 relevant data collection, analysis and PBR design so the 17 more data we have, you know, the more comfortable we 18 will feel about going forward. 19 My question is: What ought to apply until we 20 are in that comfortable position and have all that data? 21 Would the points raised on page 5 address those concerns 22 of yours or are you suggesting that we delay PBR? 23 MR. FERGUSON: No. We are suggesting that 24 those points on page 5 would allay our concern in the 25 initial PBR period while we gather better data. 26 MEMBER VLAHOS: All right. Thank you for 27 that. 28 There are four points that are set out, and || Vol. Pg.700  UCEA 1 later on you discuss your suggestions about the 2 treatment of contributed capital, plus a discussion on 3 the service quality indicators. I just want to zero in 4 on a couple of those. 5 When you proposed that an earnings sharing 6 mechanism should be symmetric, can you tell me why, in 7 your view, the Board ought to permit what may turn out 8 to be managerial inefficiency in that the utility may 9 not be able to earn up to an opportunity or to an 10 authorized rate of return maybe allowed by the Board? 11 MR. FERGUSON: In the initial PBR period one 12 concern we have is the arbitrary productivity target. 13 Given it is somewhat arbitrary, based on the data 14 collected up to now, the rate of -- the return on equity 15 that it would generate may be just as arbitrary. 16 But if you look at private industry, if we are 17 indeed private companies, there would be no cap on the 18 return on equity, so it's an imposed cap. Then, to be 19 symmetric in treatment there should be an imposed floor 20 as well. In other words, the risk should be shared both 21 ways. 22 MEMBER VLAHOS: But I believe you understand 23 the difference between a purely private sector company 24 and a utility. You understand there is sort of a social 25 contract, if you like, between the utility which is 26 given a franchise and the regulator. So where you are 27 coming from, then, is that since there is no -- since 28 there is a cap on the top, there ought to be one at the || Vol. Pg.701  UCEA 1 bottom. It's as simple as that? 2 MR. FERGUSON: Not quite that simple. You 3 mentioned managerial competency or abilities. In 4 certain jurisdictions, as David pointed out, simply due 5 to growth, okay, management could be incompetent and yet 6 the utility would achieve its productivity target. If 7 it is incompetent management, then I believe the floor 8 shouldn't exist if it's a shareholder responsibility. 9 But indeed if there is competent management at the 10 utility and it is unable to achieve productivity for 11 reasons beyond its control, then that should be shared 12 equally with the ratepayer and the shareholder. 13 MEMBER VLAHOS: At no point do you say that 14 the shareholder should be solely responsible for 15 mismanagement or underperformance? 16 MR. FERGUSON: For mismanagement possibly they 17 should be. For events beyond the control of management 18 or the shareholder that leads to a problem in the 19 productivity, I don't believe they should be held solely 20 accountable for that. 21 MEMBER VLAHOS: All right. 22 Gentlemen, you advocate a differentiated 23 productivity target for the various utilities, perhaps 24 some groupings. Basically, to your knowledge, is that 25 something that is quite doable based on the data that 26 the Board staff have been able to collect? 27 MR. WILLS: I think we made the comments in 28 the submission that the data is no better. There is no || Vol. Pg.702  UCEA 1 better data to justify that than there is to justify one 2 size fits all. It just simply seems like a more 3 equitable approach. 4 MEMBER VLAHOS: So how will we go about 5 setting those groupings? Can you help us with that? 6 MR. WILLS: Well, some of the things we talked 7 about here. We talked about earlier that we had used 8 some professional help, and I think some of the things 9 we are sitting here defending are advice that we were 10 given by our professional helpers. Quite frankly, I'm 11 squirming a little as we try to justify it. 12 We told you we brought you a grassroots view. 13 From a grassroots view, if you look at the range of 14 costs across Ontario's utilities, you know, they go -- 15 well we talked about -- I think it was $290 to $730. I 16 mean, to me it is just common sense that with that 17 disparity in starting points one size doesn't fit all. 18 So how would you do it? One thing we talked 19 about in the yardstick task force was that you would try 20 to set some sort of a mid point or a benchmark and then 21 there would be some sort of variability either side so 22 that the lowest cost per customer, or whatever you want 23 to call it, would have a lower productivity than the 24 highest one. I think the methodology of that is open to 25 some -- you know, there are some options. 26 MEMBER VLAHOS: I guess what I'm questioning 27 is whether there is enough data available for all the 28 250 plus systems. I understand that the analysis || Vol. Pg.703  UCEA 1 performed by Board staff and its consultants, it was 2 based on selected data of -- I believe it was 48 3 systems. 4 I just wondered how much effort would be 5 involved in order to place a specific utility in a 6 specific group -- and let's talk about three, four or 7 five groupings. We have to narrow where to put that 8 specific utility. We don't have that data, so I'm just 9 thinking that -- I guess I'm seeking advice as to how 10 can the Board go about placing specific utility into a 11 specific grouping. 12 MR. WILLS: You are absolutely right, that is 13 a practical problem. I think there are few practical 14 problems and maybe that suggestion simply replaces one 15 problem with another. It just seems that from our 16 group's point of view, that that is a commonsense thing 17 to do. 18 I know in the yardstick task force, the 19 conclusion that was drawn was that the only grouping 20 available that Ontario MEUs could relate to was sizing, 21 and I believe the suggestion was something like zero 22 to -- I forget the exact numbers, but it's in the 23 report -- I think it was something like zero to, let's 24 say, 100 to 10,000, 10 to 20, 20 to 50, 50 to 100 or 25 over 100 and then I think there was the suggestion of 26 just two specific groupings for Toronto Hydro and 27 Ontario Hydro because they are so different from 28 everybody else. That is just my recollection. || Vol. Pg.704  UCEA 1 MEMBER VLAHOS: So size would be one criteria. 2 MR. WILLS: Size would be one criteria. 3 MEMBER VLAHOS: There is no evidence that you 4 are aware of that this would fix the problem or even -- 5 MR. WILLS: No. That's why we are saying -- 6 we think that until these things are understood that the 7 target should be relatively conservative. 8 You know, what we are saying is with the 9 starting point of relatively high efficiency utilities, 10 and with the kind of rate increases that are expected 11 from this market-based rate of return on the -- and all 12 of these other things, the attempt to put in something 13 for productivity, it just seems like it will be dwarfed 14 by the other things, and it complicates the task at a 15 point when the industry is in transition. You have all 16 of this volatility. 17 There are a lot of things for municipal 18 utilities to be doing over the next year and having, you 19 know -- I mean, just speaking from my own point of you. 20 You know, just looking at the kind of things that we are 21 going to have to do now to come up with the productivity 22 targets and the kind of things that we are going to have 23 to -- the strategy that we are going to have used as we 24 go into the next couple of years, and how are we going 25 to handle the first phase of PBR and the first 26 generation and what is going to happen in the next 27 generation. 28 I mean, that is just one more complication in || Vol. Pg.705  UCEA 1 terms of business planning that is being thrown in on 2 top of a lot of things that have to occur in that first 3 generation. That is just my point of view. 4 Paul, I don't know if you have any comments on 5 that. 6 MEMBER VLAHOS: Mr. Wills, I was just 7 wondering whether -- you say you are from North Bay, 8 right? 9 MR. WILLS: That's correct. 10 MEMBER VLAHOS: -- whether a North Bay utility 11 has done any assessment as to the impact on the utility 12 with a different productivity factor as to the 1.25 per 13 cent that has been suggested. I mean, how material is a 14 change from 1.25 to something lower? And we can pick a 15 number. But at the end of the day, what is the impact 16 on North Bay? And you can measure that in terms of the 17 rate of return on common equity based on the Handbook 18 with some decapitalization. 19 Have you done that kind of work? Have you 20 done that kind of impact analysis? 21 MR. WILLS: No, we haven't. Our suggestion, 22 though, is CPI minus X. 23 MEMBER VLAHOS: So you are starting with a 24 productivity factor? 25 MR. WILLS: Yes. We are talking about the 26 productivity, but there are the two issues there. I 27 mean, I think, as utilities, we are coming off five 28 years of -- or five to seven years of virtual rate || Vol. Pg.706  UCEA 1 freezes. It seems like an inopportune time to have 2 rates virtually frozen into the future. 3 I think I would suggest to you that you will 4 find some utilities out there that probably have -- you 5 know, that are probably -- or have levels of service 6 that just may not be adequate in the competitive world 7 and they may actually need to increase rates. 8 I would suggest to the Board that, you know, 9 if you start getting into those individual 10 circumstances, you may actually find that the ratepayers 11 of some municipal utilities probably should be paying a 12 little more in rates and you probably should be 13 encouraging higher levels of service. 14 MEMBER VLAHOS: All right. 15 Gentlemen, I just have a couple of specific 16 questions. 17 You talked about -- and that's at page 5 of 18 your submission -- the differences in the practices of 19 electrical utilities for reading and billing. I was 20 just wondering whether the frequency ought to be a 21 service quality indicator? 22 MR. WILLS: Yes, I believe it should. 23 Also, I think it is important the number of 24 days. There is no service quality standard for the 25 number of days. I know we have run into problems in our 26 own utility of if you take a nominal 30 days for 27 billing, if for whatever reason you start running bills 28 up to 40 days, it has a huge customer impact. || Vol. Pg.707  UCEA 1 So now we have a standard of 30 days plus or 2 minus 10 per cent is what we try to achieve on meter 3 reading. 4 MEMBER VLAHOS: Was there a lot of discussion 5 about this potential service quality indicator in the 6 technical conferences? Were you here for the full week? 7 MR. WILLS: No, I was only here for a couple 8 of days. 9 MEMBER VLAHOS: Are you aware whether it has 10 been brought up by anybody else? 11 MR. FERGUSON: It doesn't stand out in our 12 minds. 13 I guess where it has stood out is primarily 14 when the standard supply issue was being discussed. I 15 think at the Alliance level what we looked at was if it 16 was a spot passthrough probably all of the Alliance 17 utilities, their preference would be to go to a monthly 18 reading cycle so that we could -- to make the whole spot 19 passthrough more manageable in terms of the billing 20 cycles and that, that it would pretty well force 21 everybody to a 30 day. 22 We talked about it in that context. I do not 23 recall us discussing it in terms of a service quality 24 context. 25 MEMBER VLAHOS: Okay. 26 There is a statement on page 6 of your 27 submission and I will read that to you. It says: 28 "We support the Board's proposal to talk || Vol. Pg.708  UCEA 1 with customers to find out what really 2 matters to them and to talk with MEUs to 3 determine whether the things that matter 4 can be practically or economically 5 measured." 6 I was just wondering about the source of that. 7 "The Board's proposal". What are you 8 referring to? 9 MR. WILLS: Okay. I wrote that and maybe 10 somebody can help me here. 11 My recollection is that somewhere deep in the 12 documentation there was a proposal that the Board would 13 do surveys from time to time. 14 I'm sorry, I can't give you the source of that 15 quote, I am just going from memory. 16 MEMBER VLAHOS: Ms Kwik, can you help us? 17 MS KWIK: That's right. It was the 18 implementation task force that recommended that the 19 Board do annual surveys to determine customer 20 satisfaction. 21 MR. WILLS: Oh, okay. So that is not in the 22 Handbook. 23 MS KWIK: Actually, I do believe we did 24 transpose it in the Handbook as well. I will have to 25 check on that. 26 MR. WILLS: I thought it was there. If it's 27 not, I apologize. 28 But I think -- || Vol. Pg.709  UCEA 1 MEMBER VLAHOS: No, no need for apologies. It 2 is, I guess, my own ignorance as to the full record of 3 the proceeding. 4 MR. WILLS: For example, I know somebody was 5 recommending that there should be a service quality 6 standard of momentary interruptions. I think that is an 7 excellent idea, but I think you really need to look at 8 the technology that would be required to track momentary 9 interruptions. You are probably looking at full SCADA 10 on every substation and distribution feeder to monitor 11 that kind of thing. It is certainly nothing that you 12 can do right now in a lot of utilities. 13 So that is just one example. 14 MEMBER VLAHOS: Mr. Wills, actually, if you 15 can just expand on that, because would it have -- 16 --- Off record discussion 17 MEMBER VLAHOS: I believe we had a gentleman 18 from DTE/Probyn who talked to this matter about the 19 technical part of it. It wasn't like a discussion but I 20 must say that at the end of the day I wasn't sure 21 whether the technology was permitting or not. Can you 22 expand on that? 23 MR. WILLS: I'm sorry, permitting what? 24 MEMBER VLAHOS: Permitting the measurement of 25 a momentary -- 26 MR. WILLS: The technology exists, it's just 27 that a lot of municipal utilities don't have it, 28 especially the medium to small ones. || Vol. Pg.710  UCEA 1 You pretty well need what is called SCADA, 2 system control and data acquisition. 3 MEMBER VLAHOS: Are we talking about a 4 substantial investment? 5 MR. WILLS: Yes, very substantial. 6 MEMBER VLAHOS: That would vary? That would 7 depend on the size of the utility? Can you buy a 8 micro-SCADA, an enlarged SCADA? 9 MR. WILLS: Yes, you can. You can also 10 partner, I suppose, with larger utilities to acquire 11 that. 12 I think OHSC would have a big problem with 13 that. You start talking about the communications 14 systems that you would need to get some of those things 15 back, I think you are talking some -- 16 MR. FERGUSON: The costs could be extremely 17 high, depending on what level you actually wanted to go 18 to to monitor those interruptions, if you actually 19 wanted to move right down to the customer level or, say, 20 just a sector of the service area and look at it. 21 I think that was the basis of David's 22 statement in here. It maybe goes back when Judy was 23 asking about the buy-in between the MEU on enforcing or 24 working with those service standards. 25 I think what we are suggesting here is -- and 26 it goes back to a statement Tom Adams made to us where 27 as LDCs we will have two boards of directors, we will 28 have the group that the shareholder appoints and then, || Vol. Pg.711  UCEA 1 very respectfully, we will have the OEB as the other 2 board of directors. 3 What we are suggesting is, we encourage the 4 communication and the discussion and try to achieve 5 reasonable levels, say, to monitor momentary 6 interruptions such that it isn't a financial hardship on 7 the utility yet the Board staff and ultimately the Board 8 is satisfied that the data reporting is coming back, be 9 it momentary interruptions, billing cycles or whatever 10 other service standards, but going forward we have a 11 meaningful dialogue between us, the Board and 12 significant customers to make sure we are getting those 13 standards right in terms of what we are going to measure 14 and at what level we are going to measure them. 15 I think what David is saying and the Alliance 16 is saying is we would welcome that discussion and we 17 would really like to work with the Board on that, 18 regardless of what they are. 19 But at this point in time what we measure and 20 the methods of measurement are so asymmetrical across 21 the utilities it is very difficult to even reach a 22 consensus on what things we should start with. 23 MEMBER VLAHOS: Thank you. 24 Lastly, I'm looking forward to your rate 25 design paper that you are going to submit but I do want 26 to ask one question now, and that is: You are 27 suggesting that one way to alleviate this bill impact is 28 to rebundle before it is sent to the customer. I was || Vol. Pg.712  UCEA 1 just wondering whether that takes away the impact of the 2 potential price change? 3 MR. FERGUSON: It doesn't take away the impact 4 of any overall price change. 5 Our concern is with the way that the 6 allocation is going to be done now is there will be a 7 shifting of costs from customers who have what I would 8 call a large installed capacity, where a large factory 9 has a correspondingly large section of distribution 10 plant assigned to it to supply the power. 11 What we are concerned with is the cost of 12 that, providing that for that customer. Some of that 13 cost is going to be unfairly shifted onto the smaller 14 industrial and residential customers. 15 So we may have rate impacts due to 16 deregulation. What we are concerned with is a shifting 17 of costs from one class of -- in the old sense, one 18 class of customer onto another which, as we know, we 19 hear a lot more from the residential class than we do 20 the industrial/commercial. 21 Politicians -- and I will be very upfront -- 22 their statement is: Residents vote. Companies don't 23 vote with a community. I think that is where you see 24 the vocal, residents are very vocal, okay; industrial 25 and commercial institutions aren't nearly as vocal. The 26 Board may find that as well. 27 MEMBER VLAHOS: Okay. But I'm not sure what 28 the answer to my question is. || Vol. Pg.713  UCEA 1 The proposal is to unbundle the rates as we 2 move forward, but you are suggesting that, well, if we 3 were to bundle them again for billing purposes then sort 4 of the problems will -- not really go away, you are not 5 suggesting that -- they will be mitigated. It is your 6 hope that they will be mitigated. I just -- 7 MR. WILLS: I'm sorry. If I could just 8 comment on that. 9 The proposal was to add one element for 10 embedded cost and then to -- which would be a per 11 kilowatt hour charge, and then that would just simply be 12 to bundle that back in again. 13 I mean, quite frankly, it could be left 14 unbundled but I think the bill is going to get fairly 15 complicated as it is, from what I can see, with 16 probably, what, five, six different elements on it at 17 least, so adding a seventh, you know, is just another 18 complication. 19 But, I mean, it could be left unbundled I 20 think is just a suggestion for simplicity. 21 I think one of the things we tried to say, in 22 our submission, is: Let's try and keep it as simple as 23 we can in this transition period. Yet, here we are 24 suggesting another element on the bill. So I think we 25 sound a little bit contradictory. 26 MEMBER VLAHOS: Gentlemen, the billing systems 27 for Newmarket or North Bay, can they -- the current 28 billing system -- can it handle the changes that are || Vol. Pg.714  UCEA 1 being proposed, in terms of itemizing or breaking down 2 the bill? 3 MR. WILLS: Ours can. 4 MR. FERGUSON: Ours can, too. 5 MEMBER VLAHOS: Thank you, gentlemen. Those 6 are my questions. 7 THE PRESIDING MEMBER: Thank you. 8 Dr. Zerker? 9 MEMBER ZERKER: Thank you. 10 Good morning, Mr. Ferguson, Mr. Wills. 11 I take it that you are advising the Board to 12 be more cautious and that we should move with hesitancy 13 and care into this transition period. 14 In doing that, you have a proposal here 15 that -- some of which my colleague has already 16 questioned you on, on page 5, and I assume that that is 17 for the -- your proposal is to accommodate the initial 18 PBR period. Is -- 19 MR. FERGUSON: That is correct. 20 MEMBER ZERKER: -- that correct? 21 MEMBER ZERKER: Could we take a step back -- 22 and I looked at your analysis of the methodology, in the 23 Handbook, for productivity and your argument -- which is 24 quite interesting -- that, if applied as you here 25 outline, it would distort the whole notion of 26 productivity. 27 So my question to you is -- I mean that is, I 28 think, what you are telling us by your example. || Vol. Pg.715  UCEA 1 MR. WILLS: If I could answer that. I 2 wouldn't call it -- would I call it a distortion? I 3 think what we have tried to say is that there is not a 4 full understanding of what is underneath the figures in 5 the municipal utilities and I have just tried to give an 6 example of, you know, why what looks like productivity 7 may not, in fact, be productivity. 8 I also talked about the -- 9 MEMBER ZERKER: That's what I call 10 "distortion". 11 MR. WILLS: Okay. 12 And just the example of, you know, a lot of 13 the so-called productivity was in high-growth utilities; 14 therefore, the productivity was a result of circumstance 15 rather than management. 16 MEMBER ZERKER: Then how would you suggest 17 what kind of measure would be more accrue, or more 18 appropriate? From your experiences. 19 Both of you have had a lot of experience in 20 the actual management of a utility, I imagine, for some 21 time, and you understand what that utility's 22 productivity analysis should depend upon. 23 I would certainly appreciate if you could give 24 me at least some overall or some generic view of what 25 you think would be a more appropriate way to approach 26 the productivity, in the utility business. 27 MR. WILLS: I will take a stab at that. I 28 don't have the complete answer to it. || Vol. Pg.716  UCEA 1 I think one of the things that we did say, 2 right at the beginning, was that we don't have the 3 answers to all of these things. 4 MEMBER ZERKER: I don't expect -- I just want 5 your experience -- 6 MR. WILLS: Okay. Just talking from a 7 practical point of view, one of the things that I think 8 that the MEA has done is that, over the years, they have 9 put out what are called the performance management 10 standards. And if you look at the performance 11 management standards, it compares utilities on various 12 factors; and these would be things like: cost per 13 thousand kilowatt hours for residential customers; 14 customers per employee; SAIDI; CAIDI -- whatever they 15 are -- the reliability standards; the cost per customer 16 on operations, maintenance, administration; controllable 17 cost per customer. There's comparison of the service 18 areas. And all of those things. 19 What you find if you look at those -- if you 20 look at those numbers, maybe one number itself is not 21 the answer. But if you are a utility and you are in the 22 lowest quartile or the wrong quartile of all of those 23 things, you are probably not one of the better utilities 24 in the province. 25 You can't take one number. You can't just 26 take cost per customer and say, "Aha! See there, their 27 cost per customer is higher", or lower, or whatever it 28 is. If something else may be -- you know, they may have || Vol. Pg.717  UCEA 1 capital cost per customer. It will all depend on the 2 utility. 3 But if you look across the range of numbers 4 and if you look at a number of those factors, you can 5 draw conclusions. 6 I mean I have been able because I have been 7 doing this for about six or seven years now. 8 MEMBER ZERKER: So this is really taking a 9 comparative approach. What you are pointing to is 10 something that I'm familiar with in the oil industry, in 11 refining: the Solomon survey. I don't know if you 12 know -- 13 MR. WILLS: I'm not familiar with it, no. 14 MEMBER ZERKER: Well, in fact, the Canadian 15 companies were using the Solomon survey -- which is an 16 American survey, or a survey across North America -- to 17 do a productivity comparison and the refineries were 18 told, in effect, "You either fit into the first quartile 19 or we will shut you down". 20 So that is the approaches -- and I have seen 21 that kind of work done. I have seen it applied, as 22 well. 23 So that is a kind of a comparative approach 24 that you suggest might be useful for our understanding 25 of productivity in this complicated utility market? 26 MR. WILLS: Well, I think -- it's been useful 27 to me. I know that as I have looked at other utilities, 28 I have drawn conclusions about them, and I think those || Vol. Pg.718  UCEA 1 conclusions are not inaccurate when I talk to them. 2 MEMBER ZERKER: I find that interesting. 3 MR. FERGUSON: Sorry. Just to add to that. 4 In the past, one of the things that many 5 utility managers focused on was -- if you looked at the 6 MEA surveys -- that category of controllable cost, which 7 is a cast-back from Ontario Hydro regulation and the 8 regulator saying, "Here's where your controllable costs 9 were". 10 That was the focus of meaningful efficiency, 11 because we all felt the controllable costs were just 12 that: those were the costs that the manager and the 13 Commission had control of. 14 So, if we looked to other utilities, we would 15 say, "This utility is well managed if our controllable 16 costs per customer are very low". The cost of capital 17 and such was totally ignored. And if you look ahead, 18 that may be reasonable because, given we've got capital 19 investment, we cannot make -- once the distribution 20 plant is built, to make it operate more efficiently is a 21 technical issue that we can't overcome. 22 So, I think in the past -- like, if the 23 Solomon survey looked at something like "What are the 24 controllable costs around operating a refinery?" -- 25 MEMBER ZERKER: It's a little different 26 situation with the refineries. But there are 27 similarities. 28 Your plant -- you are telling me that your || Vol. Pg.719  UCEA 1 plant -- you can't tighten a screw here or there, make a 2 difference, or you can't upgrade a portion of it -- 3 which is what they do do with refineries. You know, 4 they will upgrade an aspect of it, from a technological 5 point of view, whereas the -- it doesn't require a 6 complete revision, sometimes. 7 MR. FERGUSON: I'm not a mechanical engineer, 8 I'm electrical -- so. 9 But I would -- I don't know refineries, but I 10 would suggest that in terms of -- just right off the 11 top, in terms of refineries and fluid mechanics and 12 that, I would suggest that a change in a pipe or a 13 change in a valve could have much more dramatic effect 14 than, say, the change in a wire in a distribution 15 system. Okay? It's very difficult. 16 Much work has been done. Some utilities, a 17 few years ago, went after efficiency to actually reduce 18 losses and did studies on their system and spent some 19 money and did achieve, maybe, a 1 per cent improvement 20 in losses, but I think it was at significant capital 21 expense -- 22 MEMBER ZERKER: Well, the plant is -- you are 23 given a -- the plant is what's given is more or less. 24 Okay? 25 Could we turn to your proposal for the initial 26 PBR period. You proposal a price cap using (CPI - x), 27 can you give me a little more help on your x"? 28 MR. FERGUSON: The "x". All things being || Vol. Pg.720  UCEA 1 equal, the "x" in the Handbook is the productivity 2 factor, the 1.25 per cent more or less. 3 MEMBER ZERKER: You are going back to the 4 Handbook for that purpose. 5 MR. FERGUSON: Yes. The only significant 6 difference between our suggestion and the Handbook 7 suggestion is in the initial period, at least, to use 8 CPI versus an IPI number that none of us -- I don't 9 think the MEUs are comfortable with it. I don't know, 10 therefore, how our customers would be. 11 That is the most significant difference in 12 that suggestion. 13 MEMBER ZERKER: You are using the Handbook 14 productivity figure and also its ranges, the schedule 15 for X? Or is it one number? 16 MR. WILLS: I think what you have is actually 17 a couple of suggestions in the submission, and that is 18 probably what is confusing. 19 I think the X we are suggesting, at a minimum, 20 shouldn't be any more -- the average X shouldn't be any 21 more than the minimum for the group of utilities 22 surveyed. If you absolutely have to put this 23 productivity number in, we are suggesting that it not be 24 as high as 1.25 per cent without some more 25 justification. 26 We also see that there could be a range of X 27 for different utilities. I think at one point I made 28 the comment that X could even be a negative number in || Vol. Pg.721  UCEA 1 some utilities. 2 MEMBER ZERKER: Let me get to the Z-factor and 3 then I will get to the ROE. 4 I see, from your definition of what goes into 5 the Z-factor, that it is a totally different concept 6 than that which is proposed in the Handbook. Am I 7 correct? 8 It seems to me that the Handbook is looking at 9 extraordinary events that are outside of our control, 10 like an earthquake or -- 11 MR. WILLS: A change in tax regime 12 MEMBER ZERKER: -- a flood or something that 13 unfortunately God hands us sometimes, and transition 14 costs. It seems to me that that is what the Z-factor is 15 in the Handbook. 16 Here you are talking about taxes regulation, 17 compliance costs, and so on. Are we talking about a 18 different concept? That is all I want to know. 19 MR. FERGUSON: We are defining Z-factor here 20 as one-time events, and a one-time event could be an 21 event outside the utility's control. What we are 22 suggesting is that it could also be a one-time event 23 created by the utility. 24 Beyond the utility's control would be the ice 25 storm or an earthquake, where it is a devastating event 26 which requires a significant increase in cost. 27 When we go back to the question of service 28 standards, it could well be that the utility may incur a || Vol. Pg.722  UCEA 1 one-time cost to monitor service standards to install 2 the technical equipment to do the correct monitoring 3 that the Board would like going forward. 4 That could be treated as a Z-factor. Here is 5 my one-time cost of a step improvement in either 6 monitoring that service factor or improving it up to the 7 standard. 8 David mentioned some utilities may actually 9 have a negative productivity or have to incur costs to 10 come up to the norm or the expectation for the 11 deregulated world. But those thing could happen in two 12 ways: (a) it is an ongoing cost of doing business, in 13 which case it would be a productivity factor change; or 14 (b) it could be in one year a one lump sum spending to 15 bring technical equipment or whatever into the utility 16 to meet the objective. 17 Am I helping? 18 MEMBER ZERKER: Yes, I am beginning to see 19 your boundaries that you are trying to draw. But I 20 still think that they are somewhat different than that 21 proposed by -- let me put it this way: It is wider. 22 MR. WILLS: Yes, I think it is a little 23 broader. 24 I think the whole point of the submission is 25 go carefully. You have a distribution sector that is 26 working, and it is working very well, in our opinion. 27 And I think our message to you as a Board is go 28 carefully and preserve the things that are working and || Vol. Pg.723  UCEA 1 fix the things that are not working. 2 To do that, you need to be flexible. If you 3 simply take a one size fits all productivity factor, 4 then you are going to find some circumstances where that 5 doesn't fit. 6 What we are saying to you is you may need the 7 flexibility, and you may want to take the flexibility to 8 address those circumstances. 9 MEMBER ZERKER: One moment, please. I am 10 looking at the formula in the Handbook for the first 11 generation PBR. I wish I had a similar formula. 12 So your formula would be the price cap -- I am 13 looking to identify it. It is on page 2-11, in case you 14 have it there. 15 THE PRESIDING MEMBER: Could Board staff 16 provide a copy to Mr. Wills? 17 What page number, Dr. Zerker? 18 MEMBER ZERKER: Page 2-11 in the second 19 chapter. 20 On the second page of the second chapter, page 21 22 at the very bottom. 22 I am just trying to see whether or not we can 23 figure out your proposal and make comparisons so that I 24 take seriously your proposal as an improvement over the 25 Handbook proposal for the price cap. 26 What we have here is a percentage change in 27 the utility price ceiling in a particular year. The 28 first one would be the change in inflation, but you || Vol. Pg.724  UCEA 1 would use the change using CPI. 2 Then you would say minus X. Are you going to 3 change your X from what we are using here, which is the 4 productivity factor -- the change from year to year 5 using a combination of productivity and ROE ceiling? 6 Are you going to change that? 7 I am trying to figure out where your ROE comes 8 in. 9 In here, the ROE comes in the productivity 10 factor. 11 --- Pause 12 MEMBER ZERKER: I don't have to pressure you 13 on this. In your final submissions, could you do me a 14 favour? 15 MR. FERGUSON: Certainly. 16 MEMBER ZERKER: See whether or not you can 17 compare your proposal in some kind of hard way to that 18 which is here, and then we can look at it with a more 19 specific guidance when we are appraising them. Okay? 20 MR. FERGUSON: Yes. 21 MEMBER ZERKER: I think you get the idea of 22 what I am looking for. 23 MR. FERGUSON: I do, and we will do that; 24 thank you. 25 MEMBER ZERKER: Thank you. 26 I probably have some other questions. But I 27 must tell you that I thought your argument on 28 contributed capital as it relates to the gas industry is || Vol. Pg.725  UCEA 1 probably about the best I have seen. You have taken 2 seriously that point of view and argued the case well. 3 Let me just leave it at that. Thank you. 4 THE PRESIDING MEMBER: Thank you, Dr. Zerker. 5 I have a few questions, although I think 6 Dr. Zerker and Mr. Vlahos have covered most of them. 7 One of the questions that interested me was 8 your idea that there should be somebody at the Board 9 that is the contact point for municipal utilities so 10 they know who they can go to to get clarification or 11 understanding. 12 I wonder if you would explain to me how this 13 was handled by Ontario Hydro in the past, who was at one 14 stage your regulator. Did they have that sort of 15 arrangement? 16 MR. WILLS: As a matter of fact, I can speak 17 to that. That is the job I used to do about 20 years 18 ago. I used to regulate the rates of municipal 19 utilities. 20 If you go back that far when we used to do 21 rates with pencil and paper and before the days of 22 computers, I think it was a very good relationship 23 between the regulator and the municipal utilities 24 because you had a fairly good idea -- I actually used to 25 do the rates for the smaller utilities. The larger 26 utilities would do their own rates. 27 You always knew who you were dealing with. I 28 have a lot of questions right now about specific things || Vol. Pg.726  UCEA 1 in our utility that I would like answered. I can't get 2 the answers from the Rate Handbook or the material that 3 is available. 4 If I had a specific contact at the Board, if 5 there was somebody that was designated to deal with a 6 certain group of utilities, you would get some 7 continuity in terms of who you talked to and maybe the 8 answers that you got. 9 Again, I think rates over the past what, 20 10 years, have got to the point where they were fairly 11 alternated. I think in that way Ontario Hydro was able 12 to pull all -- I mean they basically pulled all of the 13 staff out of the regional offices. They used to have 14 staffing in what, five or six regional offices. They 15 would have individuals that were specifically 16 responsible for municipal utilities. 17 Once the regions were disbanded, all of that 18 came into a central regulatory office. At that point 19 there became very little dialogue in terms of 20 relationships between, you know, the regulatory affairs 21 and the utilities. 22 THE PRESIDING MEMBER: But there was still an 23 identified contact person for a group of utilities. 24 MR. WILLS: That's correct. Yes. 25 THE PRESIDING MEMBER: How many utilities, in 26 your experience, could one rate panellist or whatever 27 you called yourselves at the time relate to? 28 MR. WILLS: The problem with it was that all || Vol. Pg.727  UCEA 1 of the rates had to go effective January 1 and that was 2 a real problem because you had a crunch where you were 3 on the road and, you know, late November and early 4 December, going to Commission meetings and presenting 5 rate packages and getting all of these things through. 6 They then had to get in to Head Office by probably the 7 first part of December for rate increases that went 8 probably the first part of -- sorry, the 1st of January. 9 In that case, you know, I think -- I know in 10 one region I think they were handling about 15 or 20 11 municipal utilities under that circumstance. If, and I 12 am talking off the top of my head here -- obviously if 13 you were to spread that out over a year, then you could 14 handle a lot more utilities. 15 That's kind of a tough question because I 16 think the indication in the Handbook is that possibly 17 the rate changes would all be effective in March. You 18 have got the same kind of crunch that we would have had 19 doing them on January 1. 20 MR. FERGUSON: The dialogue, how many people 21 it would take, I don't know. I'm also a former Ontario 22 Hydro person. You must believe the province is made out 23 of us. 24 THE PRESIDING MEMBER: I made it David's job. 25 MR. FERGUSON: My position was primarily 26 liaison on transmission and subtransmission problems of 27 utilities. There were three of us managed the GTA at 28 that time on those issues which was Kitchener to || Vol. Pg.728  UCEA 1 Peterborough, the lake to basically Barrie. 2 In that case there wasn't one crunch date. 3 The issues just evolved over the year or every time a 4 lightening storm came through, whichever came first. In 5 PBR it is recognized as we move into this a lot more 6 will be the responsibility of utilities. 7 What's important then is just the ongoing 8 dialogue. I think the point David's making and I agree 9 is just a person we know that we talk to and there's 10 continuity in that person all the time. For example, it 11 would be for the Alliance one person could probably 12 easily manage the Alliance. When we get together, they 13 come out and talk to us, but it would just be continuity 14 for the questions, regardless of whether the issue was 15 standard supply, capital betterments, PBR, whatever. 16 I would think that a person -- 10, 15 17 utilities at least to give it a try. 18 THE PRESIDING MEMBER: Judy's got spare time. 19 MR. FERGUSON: It would help us a lot on this 20 side and I think it would really help our relationship 21 with the Board if we had continuity in that contact 22 person. I would suggest then it would be Board staff to 23 really wave the flag and say "Hey, this is too much for 24 me". I don't think we could give you a definite number 25 though as to how many one could handle. 26 THE PRESIDING MEMBER: Thank you. The 27 question that came from your earlier submission, you 28 were mentioning the good performance, comparative || Vol. Pg.729  UCEA 1 performance of the Ontario utilities versus the American 2 utilities. Then you also discussed Ontario Hydro 3 Services Corporation, Ontario Hydro Networks 4 Distribution Corporation. 5 You also made a reference in your submission, 6 that's the August 17 submission on page 20. I will read 7 it to you. It says: 8 "While items 1 to 6 could be considered 9 as Operations and Maintenance items 7 to 10 13 are what MEUs would classify as 11 Billing, Collecting and Administration 12 activities." 13 One of the questions that went through my mind 14 is when one is comparing, say, the O&M between the 15 utilities, there is an example, are we comparing the 16 same activities in the measure of O&M costs in the U.S. 17 utilities or the Canadian utilities, Canadian municipal 18 utilities, or between the municipalities and Ontario 19 Hydro when we talk about a word like O&M dollars per 20 customer? 21 MR. WILLS: They wouldn't be exactly the same, 22 but they should be similar. I think that's one of the 23 things that the data is not transparent. Looking at the 24 Ontario Hydro numbers, I have no more information at a 25 level below what is in the submission. My judgement is, 26 I think, in that statement that the category of costs 27 that are being identified look to be about the same. 28 When you look at something, the last one I || Vol. Pg.730  UCEA 1 think is what, customer care? It's hard to know exactly 2 what that is, or distribution administration or 3 something. 4 THE PRESIDING MEMBER: You are certainly 5 right, customer care granted in lieu in distribution. 6 MR. WILLS: I mean that's different 7 terminology than we use. Unless you dig into that 8 number and compare it and see exactly what is in there, 9 but you will find exactly the same thing in the 10 municipal utilities. You will uncontrollable costs. 11 You will find the cost of a building. Then what you 12 find is that the Water Department shares the same 13 building and that there is offsetting revenue some place 14 else. 15 If you simply compare controllable costs, you 16 are not going to draw the right conclusions. There's 17 just all kinds of examples of those kind of things. You 18 will find utilities that charge certain costs to capital 19 automatically so they are controllable costs for 20 customer and lower. 21 That's why I said earlier if you look at a 22 range of indices, there will be enough that will come 23 across in that picture hopefully that you can draw 24 comparisons between utilities. 25 THE PRESIDING MEMBER: I think my last 26 question relates to this question of what is being done 27 with the PBR formula. The PBR formula is setting a rate 28 going forward. Stage one is unbundling to try and || Vol. Pg.731  UCEA 1 separate out the commodity from the distribution costs. 2 That is Appendix A. Then there is a mechanism to adjust 3 the costs as you go forward. That consists of an 4 inflator. You are suggesting CPI. The book says IPI. 5 Then there is a productivity factor. Then there's some 6 Z-factors. 7 At the end of the day we arrive at some rate 8 going forward. You are suggesting that we should defer 9 PBR for a period of time until the data and appreciation 10 of it is better understood. I didn't quite understand 11 how you would suggest the rates be set until a time when 12 you felt that there was a better understanding of the 13 PBR implications. 14 Supposing you said that would appear in two 15 years time, how would you do the rates between now and 16 two years ahead? 17 MR. WILLS: Well, we appreciate that -- I 18 think we have this idealistic wish that we could hang on 19 to the past somehow, but I think we recognize that 20 things are changing, that we have to adapt. We know 21 that the Board has to apply some regulation to it. 22 We are saying well, let's be flexible. I 23 think the thing is that the CPI minus some sort of a 24 productivity -- we are saying to the Board "Okay, we 25 know you have to do something with productivity". Maybe 26 you don't. 27 The X-factor is where you are headed. In the 28 first three years, what is its impact going to be? I || Vol. Pg.732  UCEA 1 mean, I think that was one of the comments that we made, 2 that it will be dwarfed by all of the other things, you 3 know, so that if you feel that you absolutely have to 4 have an X-factor, we have given you some suggestions on 5 what those might be. I think the point is that it 6 shouldn't be too aggressive. 7 But if there is an X-factor, maybe you can 8 consider a range of X-factors, you know, so that for the 9 more efficient utilities, if you have to have an 10 X-factor, they would have a lower number than the 11 utilities that perhaps hadn't been -- let's call it, you 12 know -- as efficient, you know, the higher cost 13 utilities. 14 I think we are just trying to address some 15 reality there mixed with a little bit of idealism. I 16 don't know if that helps. 17 THE PRESIDING MEMBER: Ms Kwik seems to have a 18 question of clarification. 19 MS KWIK: Thank you, Mr. Chair. 20 I need to clarify. Mr. Wills, I would like to 21 acknowledge your memory serves you right; mine didn't. 22 You are quite right that in the Rate Handbook we had 23 included the aspect of the Board conducting the surveys, 24 the customer surveys. It did get transposed from the 25 task force into the Rate Handbook. 26 Thank you, Mr. Chair. 27 THE PRESIDING MEMBER: Thank you, Ms Kwik. 28 Mr. Wills and Mr. Ferguson, we are very || Vol. Pg.733  UCEA 1 appreciative of your coming and presenting to us. They 2 were very helpful comments you made. We shall certainly 3 look forward to your final submission, including that 4 item which identifies your suggestion as to how one 5 might deal with rate setting as we go forward. 6 Also, Dr. Zerker reminds me of the 7 understanding of the formula or how your suggestions 8 might be incorporated in a formula. So thank you very 9 much indeed. 10 MR. FERGUSON: We thank the Board for its 11 patience and wish you a happy Thanksgiving. 12 THE PRESIDING MEMBER: Thank you. 13 MR. WILLS: Thank you very much. 14 THE PRESIDING MEMBER: Mr. Roman, if it is all 15 right, could we have a break now and then come back? If 16 we could break now and then we would go through with the 17 next two submissions? 18 So we will break for 15 minutes and come back. 19 MR. ROMAN: Thank you. 20 --- Upon recessing at 1040 21 --- Upon resuming at 1100 22 THE PRESIDING MEMBER: I have the sequence 23 right I think. It is Mr. Roman this time for the Halton 24 Hills group. Thank you. 25 Would you like to start? 26 MR. ROMAN: I'm sorry? 27 THE PRESIDING MEMBER: Can you hear me? Would 28 you like to start? || Vol. Pg.734  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 MR. ROMAN: Now I can hear you. Thank you. 2 THE PRESIDING MEMBER: I have to learn to 3 speak forward, so perhaps to remind everybody, including 4 myself. The microphones don't pick you up unless you 5 get closer. 6 PRESENTATION 7 MR. ROMAN: Thank you, Mr. Chairman. 8 I am here by myself today representing the 9 Halton Hills Hydro Utility and the City of Peterborough. 10 My presentation will deal with two main issues 11 specifically, but also will be preceded by a substantial 12 introduction and background section to set the context. 13 I must say also that I was enjoying the 14 questions you were asking the previous presenters 15 because some of our presentation will be along the same 16 lines. 17 First of all, by way of introduction, it is 18 common observation that most governments and perhaps by 19 extension most government agencies make their most 20 serious errors in the first 90 days when they are new on 21 the job and then will spend a lot of time trying to 22 correct that. 23 PBR has provided a wonderful debate for 24 consulting economists who have a product to sell, and 25 it's a good product, and for lawyers who write lengthy 26 briefs. But the question I would ask you today is: Is 27 there a real world policy basis for this in the 28 municipal context of Ontario? Are we really imposing a || Vol. Pg.735  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 mousetrap for people who don't have mice without 2 figuring out how the mousetrap will work and whether it 3 is indeed a better mousetrap? Is the Board's process of 4 PBR decision-making too quick? 5 There are certain issues suggested in Order 6 No. 4, Mr. Chairman, and these issues have caused some 7 consternation because they seem to be fairly narrow 8 technical issue and they seem to ignore the fundamental 9 issues raised by the parties. A number of the people I 10 have spoken to are concerned that the way PBR was 11 presented at the seminar -- I attended the one in 12 Toronto and there were others -- was as though the Board 13 had already made up its mind that it was going to 14 introduce the Handbook or something very substantially 15 like the Handbook and that all of it was left to debate 16 were the minor details of it. If that is correct, then 17 much of what I am going to be saying to you is a waste 18 of time, but I hope it is not. 19 I have reviewed the submissions of the other 20 parties and the impression has been that they have been 21 criticizing not just the details of the Handbook but, in 22 their polite way, the entire PBR regime, and that some 23 of these criticisms are, frankly, devastating. I would 24 mention those of Mr. Adamson in his two papers, the 25 papers Acres submitted, the MEA and the Alliance, from 26 whom you have just heard. 27 The concern I would have is that if the Board 28 were simply to ignore these serious criticisms pointed || Vol. Pg.736  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 out the Board could lose credibility in doing that and 2 that the Board must do more than merely adjust a few 3 details of the PBR Handbook as proposed. The Board is 4 not too far down the road to turn back or at least to 5 stop and study the matter and think about it further. 6 The need to introduce something very much like 7 PBR, a sort of automated process, if I may call it that, 8 may come from the impulse that there is no time to hold 9 a separate hearing for every wiresco, and that we 10 understand. Although that is true, it does not mean 11 that the PBR Handbook is the only answer. There are 12 probably other answers. The cost of introducing PBR in 13 haste now and then changing it to something else is 14 probably going to be a lot higher on all the parties you 15 regulate and yourselves than considering alternatives 16 from other consultants possibly, from all the 17 submissions you have received and selecting the most 18 promising solution in six months or in a year's time. 19 I would suggest that you not make the 20 assumption that any PBR that complies with a year end 21 timetable is better than nothing. That is not 22 necessarily true. 23 Moving beyond the introduction, I want to 24 discuss by way of background also, the legislative basis 25 for rate regulation. I feel almost compelled to discuss 26 this because I am a lawyer and lawyers love to talk 27 about legislation. So if what I say seems trite, I make 28 the apology that I'm a lawyer and we are here to give || Vol. Pg.737  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 you a penetrating glimpse into the obvious. 2 First of all, there is no statutory 3 requirement to use PBR or any other method. So when my 4 friends from the Alliance said a moment ago that you 5 have some obligation to use PBR, with respect, I 6 disagree. There is no legal obligation to use PBR or 7 any other method in determining whether rates are just 8 and reasonable. You are here to use your judgment and 9 that is why we have the OEB and not a computer, because 10 you do have judgment. You have judgment and you can 11 exercise that judgment with discretion, and you have the 12 discretion to use any reasonable method you choose. 13 For a public sector -- and that is 14 publicly-owned wires companies -- it is my submission 15 that the Board does not need to use any ex-ante method 16 of approval, and you don't need to use a cap. You could 17 use a guideline. For example, you could say: We are 18 prepared to allow any MEU a maximum 10 per cent ROE 19 without any application for anything. We will use that 20 as a ceiling for the next year or two while we study the 21 question, or six months, however long it takes. If 22 anybody feels they need more than that, they can apply 23 to the Board and show us why they need more or why they 24 think they should have more. 25 I ask the question, perhaps rhetorically: If 26 that was the rule would there really be any 27 applications? There may well be no applications. 28 As to why that might be, I will come back to || Vol. Pg.738  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 that in a minute. 2 A number of the submissions, including a 3 number with which I have indicated have presented very 4 significant criticisms of the Board, have fallen prey to 5 a popular misconception, and that is that the 6 legislation creates a duty to commercialize. 7 In my submission, there is no such duty. 8 There is only a duty to have shares held by a 9 municipality, that is to corporatize. To corporatize 10 does not equal to commercialize. 11 Where the White Paper uses the expression 12 "commercialize" it doesn't define that term, but it uses 13 it in the context of corporatize, that is to say, to be 14 set up as an OBCA, Ontario Business Corporations Act, 15 corporation. 16 Now, why did we need to introduce the right to 17 corporatize in the legislation? Why didn't we just 18 leave it the way it was? 19 The answer, of course, is that under the old 20 legislation that existed under the Public Utilities Act 21 and under the Power Corporation Act, a municipal utility 22 did not have the legal right to sell its entire 23 undertaking, it could not create any corporations and it 24 could not amalgamate with anything else. There were no 25 other corporations. 26 This was considered an unacceptable situation 27 because it was a very rigid situation and each 28 municipality that wanted to amalgamate -- and you will || Vol. Pg.739  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 recall that there were suggestions that there were too 2 many MEUs -- would have required a special Act of the 3 legislature. 4 So what the legislation has done, the new 5 Energy Competition Act has done, is it has given the 6 municipalities the legal right to amalgamate and to set 7 up corporate structures if they want with limited 8 liability, which can be important when you are moving 9 into a competitive market situation and you don't want 10 to make the municipality liable for potential losses of 11 the municipal electric utility, particularly if the 12 municipal electric utility is going to be getting into 13 competitive ventures. 14 That does not mean and that says nothing about 15 a legal requirement or, for that matter, a policy 16 requirement to maximize your rate of return and to 17 operate your MEU as if you were a privately owned 18 utility. 19 Remember that although we will now have shares 20 instead of no shares, that does not mean that they will 21 be privately owned or that they must be operated on a 22 profit maximization basis. Those economists and others 23 who have written papers to you and submissions to you as 24 if that was the assumption, I would submit, have made an 25 assumption that would be true in the context of 26 privately owned utilities in the U.S., which is where 27 much of the ideology and the philosophy and the economic 28 theory that your consultants and others have presented || Vol. Pg.740  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 to you have originated. 2 But I wish to emphasize that there is no legal 3 duty to earn a commercial rate of return on equity. 4 After the formalities of incorporation and 5 licensing have been met there is no legal impediment to 6 business as usual, which is to say power at cost with 7 little or no return on equity if that is what the 8 municipality wants to do. Many of the municipalities we 9 have spoken to have suggested to us that that is what 10 they want to do. 11 If that is the case, then we may be spending a 12 great deal of time and a great deal of money building a 13 mousetrap for people who don't have mice. 14 Now, what is the policy basis for rate 15 regulation? I have dealt so far with the legal basis, I 16 will shift now to the question of policy. 17 Again, it is trite but true that the purposes 18 of regulating the rates of monopoly wires businesses are 19 threefold: to ensure open access to wires for 20 competitors; to protect consumers from excessive rates; 21 and to encourage economic efficiency as a surrogate for 22 a competitive market through appropriate incentives. 23 PBR is related to the second and third of 24 these objectives. 25 I would submit to you that PBR is unnecessary 26 to achieve the second goal, which is to protect 27 consumers from excessive rates. 28 Ontario Hydro prevented excessive rates || Vol. Pg.741  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 without this, although that is not by any means the sole 2 or the conclusive argument for it, but we have done 3 without PBR for many years. We don't use a board to 4 regulate other monopoly infrastructure rates of 5 municipalities, such as water, parks, public transit, 6 nor do we care as a society -- or nor have we thus far 7 cared what the return on equity is for these services if 8 the owner is a municipality. 9 For example, one might ask, what is the ROE of 10 the TTC? I would suspect, without knowing, that it is 11 probably negative, but it is not a question that we have 12 a board regulating. 13 Where the end user and the municipal voter are 14 the same functionally the utility is like a co-operative 15 because it is operated for the benefit of members and 16 the need to cap rates or to control rates to prevent 17 gouging of consumers is greatly reduced. 18 To put it another way, there is no economic 19 conflict of interest between shareholders and customers 20 as there is with the privately owned utilities. 21 Some U.S. States do not regulate 22 municipalities or do not regulate co-ops at all. There 23 are very many permutations and combinations of this. 24 For example, Georgia does not regulate co-ops but it 25 does regulate municipalities. Louisiana does not 26 regulate government or municipally owned utilities. 27 Michigan regulates co-ops but not municipalities. 28 So there is inconsistent treatment of this, || Vol. Pg.742  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 but there are certainly a number of States in the U.S. 2 that have taken a different view of it and have not 3 imposed PBR Handbooks on municipal utilities or on 4 co-ops which our municipalities are substantially 5 similar to. 6 As long as the provincial or the municipal 7 entity owns the wiresco, why do we need to have an 8 extensive debate about whether it should have a 10 per 9 cent or a 12 per cent maximum return, when the political 10 incentive is still to minimize and not to maximize 11 rates? 12 PBR changes the nature of the regulatory game 13 from one where you have hearings where you can see the 14 whites of their eyes to one where the regulatory gain 15 becomes one of an arithmetic formula. 16 I would submit to you that PBR is not 17 particularly good at achieving the third goal, economic 18 efficiency in publicly owned entities. 19 I make no argument about privately owned 20 entities, although I would probably suggest it is a 21 crude tool even there, but it is not particularly good 22 in publicly owned entities which are motivated by 23 providing an essential service at the lowest cost to the 24 voters rather than profit maximization. 25 If you think about the logic of a municipality 26 seeking to profit maximize, a municipality that wants 27 extra revenue would be better off after what we are 28 calling here in quotes "like taxes", which is payments || Vol. Pg.743  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 in lieu of taxes, by raising their water rates or by 2 raising their taxes rather than electricity. That is 3 because they would retain 100 per cent of the money that 4 way instead of only 55 per cent after payments in lieu 5 of taxes. 6 So electricity rates are only approximately 7 half as efficient at increasing revenue as other non-tax 8 methods. What municipality in its right mind would want 9 to increase its electricity rates, which it would now 10 have to show on a desegregated bill to its customers and 11 justify to the customers paying an unnecessary 45 per 12 cent tax, or payment in lieu of tax, when other 13 municipalities may not do the same? How does a mayor 14 and a council justify that to the voters? 15 I would submit that this is something that has 16 not been considered in this PBR exercise so far but 17 needs to be. I will come back to this issue in a little 18 while. 19 PBR, as implemented in the Draft Handbook, 20 rests on a number of highly controversial assumptions 21 which need to be questioned and studied before their 22 acceptance as being valid. 23 I will just give you a few examples of this. 24 First of all, total factor productivity data 25 are meaningless -- we assume are meaningful and reliable 26 in the Ontario municipal setting. We do this when we 27 set up a PBR Handbook despite the fact that there is no 28 consistent standard definition of "customer". So when || Vol. Pg.744  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 you look at something per customer there is no 2 consistent definition of "customer". 3 A customer is somebody you bill, and that 4 could be a large office tower or an apartment building 5 or a small house. Each is a customer. 6 By the way, the same problem arises with 7 reliability data. When you have outages per customer, 8 that could be Stelco or it could by my apartment. It is 9 per customer. Whereas the impacts, of course, are quite 10 different. 11 The second assumption we are making is that 12 changes in product mix will not skew or slump the TFP 13 data. In other words, increases in TFP as measures 14 equal real increases in efficiency. That is a big 15 assumption. 16 Consider, for example, a vehicle manufacturer 17 that manufactures X vehicles one year and X vehicles the 18 next year; no change in productivity. But let's say 19 that some of the vehicles are Cadillacs and some of the 20 vehicles are Chevrolets, and in year two they produce 21 twice as many Cadillacs and half as many Chevrolets. 22 What has happened is the output mix has changed. 23 Electricity is not a single product. It is 24 many products with many potential qualities, and there 25 are changes in the output mix. As there are changes in 26 the output mix, you may not be measuring the same thing 27 in year two or year three or year four as you did in 28 year one. || Vol. Pg.745  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 Your PBR Handbook assumes otherwise. It makes 2 that contrafactual assumption. 3 All measures of productivity, I would submit 4 to you, lead ultimately to a conceptual morass. I have 5 spent many, many years dealing with this issue in the 6 telecom industry, in the airline industry, in the 7 railway industry, and the problems are always the same. 8 Take one number and divide it by another and assume that 9 it is meaningful, and you find that there are all kinds 10 of conceptual problems. The problems do not go away 11 when you collect more data. The problems are 12 fundamental to what it is that you were trying to 13 measure. 14 Ultimately, if I can take you to the bottom 15 line on this issue, the notion of productivity is 16 primarily an exhortative concept, like truth or justice 17 or virtue. But when you try and measure it, you find it 18 is like nailing Jell-O to a tree. 19 You also assume in the PBR Handbook that 20 economic efficiency is the only important goal and that 21 the trade-off between price and service quality doesn't 22 matter. PBR does not regulate service quality as such. 23 It treats it as external and largely irrelevant. 24 Not only could the output mix be changing but 25 service quality could be changing, and the quality of 26 electricity, the cleanliness of electricity, which is on 27 a continuum with service quality, could be changing. 28 You are also assuming -- and you have heard a || Vol. Pg.746  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 lot about this -- that all utilities are equally 2 efficient or inefficient at the beginning of the process 3 and that they could all equally easily achieve the same 4 percentage cost increases or decreases. And I will be 5 coming back to that issue. 6 We are also assuming that the proposed 7 percentage cost reductions and the corresponding ROE 8 caps have some empirical basis and provide a defensible 9 starting point. 10 You are also assuming that PBR will not create 11 perverse incentives to reduce expenditures which will in 12 the long run reduce customer satisfaction to lower 13 reliability or lower service quality. 14 Finally, you are assuming that the proposed 15 service quality measures are adequate for analysis on an 16 annual basis, for comparison among wirescos with 17 different service characteristics and for linking 18 service quality in an as yet unspecified way with an 19 allowed ROE. 20 You have these various measures of service 21 quality, which I would suggest to you are not 22 particularly good measures, and then you don't say 23 anywhere how, if somebody reduces their performance in 24 relation to those measures, that will be factored in to 25 a reduction in the cap on the ROE, assuming all along 26 that the cap on the ROE is relevant anyway. 27 To conclude this general point, is PBR the 28 right kind of incentive regulation for Ontario, or is it || Vol. Pg.747  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 trying to force a square peg into a round hole? 2 As a woodworker, I can tell you that it is 3 possible to force a square peg into a round hole if you 4 hammer it hard enough and often enough, but what will 5 happen is that you will crush the surrounding fibres and 6 you may split the board. 7 I don't mean this Board; I mean the wood 8 board. 9 THE PRESIDING MEMBER: I think you used "wood" 10 in your text. 11 MR. ROMAN: Yes, I did. 12 Now I want to turn to the first of the two 13 specific issues I was dealing with: contributed 14 capital, which is a submission that Halton Hills Hydro 15 is making on its own. That is an issue of great concern 16 to Halton Hills Hydro of course, because it has a 17 substantial amount of contributed capital. 18 If the Board intends to regulate by assuming 19 that maximizing return on equity is the goal, subject 20 only to ceilings tied to cost savings, then consistency 21 alone would require that all equity capital be treated 22 alike for return purposes, regardless of source. 23 By way of example, if somebody inherits an 24 asset or builds it or purchases it, that doesn't matter 25 in considering what he should sell it for, because that 26 should be its market value. 27 The term "contributed capital" is a misnomer 28 and is seriously misleading in the Ontario MEU context || Vol. Pg.748  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 because, as others have also told you, in our situation 2 all equity capital is contributed capital. 3 None of the notional equity was paid in by the 4 shareholder, as in the gas industry or in other 5 industries, in return for investing in shares. That is 6 how shareholders buy their shares. 7 There was no shareholder before and all the 8 money, except for the debt, was contributed directly or 9 indirectly by customers. The owners, who were 10 effectively the trustees or agents for the customers, 11 earned virtually no profit on this capital, and what was 12 earned was put back into the utility to expand the 13 service to repay debt or to lower rates. 14 For the sake of consistency, if a utility is 15 in future to be denied a return on any equity capital 16 which was not invested by shareholders but was 17 contributed by customers, then no Ontario wiresco should 18 be allowed any return on its equity, regardless of its 19 performance under PBR. 20 A number of people have dealt with past and 21 future contributed capital as though they were very 22 different, and I would submit to you that that may be 23 conceptually a problem too. 24 The PBR Handbook's proposed treatment of past 25 and future contributed capital is as if the mere 26 formality of corporatization converted the equity 27 capital of a municipally owned utility into capital 28 invested by the shareholder in a commercial enterprise. || Vol. Pg.749  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 And that is not the reality. 2 As I said before, corporatization should not 3 be confused with commercialization or privatization. 4 Unless a municipality or a municipal utility is partly 5 or totally privatized, all equity capital will continue 6 as before to be contributed directly or indirectly by 7 customers. 8 Halton Hills Hydro will not become an Enbridge 9 Consumers Gas or a Bell Canada merely by creating a 10 corporation which has share capital. Therefore, Halton 11 Hills Hydro's equity capital should not be regulated as 12 if it was the investment of private shareholders in one 13 of these privately owned entities in return for 14 receiving shares. 15 Intragenerational and intergenerational equity 16 issues arise in the context of deciding which customers 17 should make which contributions to which assets at which 18 time, and the Board may wish to explore this issue in 19 future to ensure fairness of treatment to all customers. 20 However -- and this is an important 21 "however" -- this issue has nothing to do with whether a 22 return should be allowed on so-called contributed 23 capital. 24 The Ontario Court of Appeal held in the Nepean 25 case -- and I apologize that I forgot to give you the 26 citations for the Trial and the Appeal divisions of 27 that, but I will provide that later. 28 The decision in that case was that claims for || Vol. Pg.750  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 inequity arising from past contributions into an asset 2 pool in which the contributions are merged and no longer 3 specifically identifiable cannot be accepted because the 4 calculation would be an impossible task. 5 The economist, Mr. Adamson, in his most recent 6 submission to you made the same point. The lawyers and 7 the judges and the economists seem to agree on this. 8 Once you put all water into Lake Ontario, it's difficult 9 to tell which cup the water came from originally. 10 This reasoning is also applicable to an 11 attempt to distinguish some customers' contributed 12 capital from other customers' contributed capital for 13 purposes of regulating the ROE. 14 I turn now to my second issue, the proposed 15 PBR formula on behalf of both Halton Hills Hydro and the 16 City of Peterborough. The first comment we would make 17 is that the PBR Handbook treats the olympic athlete and 18 the couch potato as though they were equally athletic. 19 It rewards each on the basis of delta reductions in 20 cost. 21 A high cost utility should, other things being 22 equal, find it easier to trim the fat than a utility 23 that is already very lean. Under PBR as proposed, a 24 high cost utility would be permitted a higher return 25 than the lower cost utility even though the lower cost 26 utility is likely to be more efficient than the high 27 cost utility throughout the period. That is because the 28 low cost utility is unlikely to be able to achieve the || Vol. Pg.751  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 same delta cost reductions. Yet the greater efficiency 2 should be rewarded throughout rather than penalized. 3 This talks to a need to calibrate the system 4 initially rather than operating with it uncalibrated. 5 The reasons given for using the contradictory 6 initial calibration is that we do not have good enough 7 productivity data to compare MEUs so we cannot do 8 otherwise. 9 Whenever I hear we do not have something that 10 is good enough, I always ask the question "Good enough 11 in comparison to what?". I would respectfully submit 12 you ask yourself the same question. 13 First of all, we will never have good enough 14 data to compare productivity accurately because of 15 endemic differences in metering, in determining what is 16 an output, what are the different products that are 17 within the service provider. If such data are 18 prerequisites to the fair use of PBR, that alone is a 19 good reason to look for another method of regulation. 20 Second, the data we have is provided for most 21 municipalities of any size in comparative reports 22 published by the MEA. While conceding that these data 23 may be imperfect, I would submit that they are far 24 better than the assumption that there are no differences 25 in productivity now and that all utilities are equally 26 efficient or inefficient or productive or unproductive. 27 It is, therefore, better for the Board to use 28 an assumption that is substantially correct for most || Vol. Pg.752  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 customers and most MEUs than one that is plainly wrong. 2 The Board could reward particularly efficient 3 utilities in two ways. First of all, you could adjust 4 the maximum returns upward for cost reductions (a) 5 through (e) on your table by a starting efficiency 6 factor. 7 Alternatively, you could leave the maximum 8 return the same as in your alternatives (a) through (e) 9 but allowing these returns to be earned at a lower 10 percentage cost reduction. That would be the second 11 technique. 12 Now remember that this argument does not 13 advocate that you use the PBR Handbook as is. This is 14 an alternative argument. If you are going to use the 15 PBR Handbook, if you are going to stay with it, then 16 these are ways you could reward particularly efficient 17 utilities. 18 The burden of showing that a particular 19 utility is more efficient than average should fall on 20 the utility. A utility that is less efficient than 21 average, again by means of these inevitably somewhat 22 arbitrary productivity measures, may have all manner of 23 legitimate reasons for this. I call these reasons, not 24 excuses, because they are reasons. 25 These could include, first of all, that they 26 made little or no use of development charges to finance 27 expansion. Hence, they have a higher than average level 28 of debt to be serviced. || Vol. Pg.753  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 I digress here for a moment and suggest to you 2 that that may be more relevant to a correlation in size 3 or anything else because utilities are capital 4 intensive. 5 Those utilities that in the past have grown 6 rapidly and made extensive use of development charges, 7 in my experience, will tend to have lower rates, or if 8 you look at it the way we used to look at it as a 9 percentage markup of the Ontario Hydro cost of 10 electricity, we will have lower markups. 11 A large part of the reason for that is because 12 they have been using capital from developers and from 13 new customers rather than capital from existing 14 customers. That has kept the rates down or kept the 15 debt levels down. 16 Another argument may be that it is 17 particularly difficult and costly to have their service 18 territory. Toronto Hydro, for example, can't shut down 19 Yonge Street to do construction with the same ease as 20 another municipality that does not have the same degree 21 of traffic density. 22 I recall almost 20 years ago at a Telecom 23 hearing in B.C. asking B.C. Hydro why their productivity 24 was so much lower than Bell Canada. They said that Bell 25 Canada doesn't have mountains. Try and locate towers on 26 mountains with helicopters. That costs a lot of money. 27 Try and maintain them. That costs a lot of money. 28 If you just look at number of poles per || Vol. Pg.754  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 customer, you don't get the answer to that. This is the 2 real problem. Service territories are heterogeneous. 3 Another factor may be a substantial recent 4 increase in debt to pay for expansion or modernization 5 or an unfavourable collective agreement or work rules 6 which reduce the productivity of labour or a recent loss 7 of customers through plant shutdowns. 8 One municipality we have spoken to has 9 something like 68 per cent of their load taken by four 10 large industrials. If those four large industrials take 11 out a cogen and disconnect from the system except for 12 backup, what is that going to do to the productivity 13 data of that utility? You are going to see more of this 14 in the years to come. There could be shutdowns, 15 self-generation or bypass. 16 Utilities which on these numerical measures 17 are less efficient than the average should not be 18 penalized except by showing that there is inefficiency 19 that is due to the fault of the utility. The burden of 20 showing that a particular utility is less efficient than 21 the average and that this should fall on the utility, 22 either in whole or part, that burden should fall on 23 whoever alleges it. 24 The applicant for such an order from the Board 25 could be a customer or a group of customers or it could 26 be the Board staff. The onus should fall on whoever is 27 making that argument. 28 In conclusion, new regulation, new techniques || Vol. Pg.755  HALTON HILLS HYDRO/PETERBOROUGH, Presentation 1 for regulation create new incentives and new 2 disincentives. We would urge the Board to make sure 3 that your mix of incentives and disincentives is, first 4 of all, relevant and, second of all, not perverse or 5 harmful. 6 I thank you for your patience. I am open to 7 answer any questions the Board may wish to put to me. 8 THE PRESIDING MEMBER: Thank you, Mr. Roman. 9 Do Board staff have any clarifying questions? 10 MS KWIK: No, we do not, Mr. Chair. Thank 11 you. 12 THE PRESIDING MEMBER: Dr. Zerker. 13 MEMBER ZERKER: I could still say good 14 morning, Mr. Roman. 15 Mr. Roman, I also attended that session. I 16 thought that the staff -- the workshop session in 17 Toronto, and I thought the staff made it pretty clear 18 that the Handbook was the work of the staff and that it 19 still had to be -- all the work still had to be done to 20 put out a final -- all the decisions still were open and 21 had to be made to put out a final Handbook. I simply 22 want to reiterate that that is the position. 23 MR. ROMAN: That is certainly what I read of 24 it too and that is certainly what I told people who said 25 "Why should you go down there and represent us when 26 everything just looks so final?". I said to them "That 27 book's final in the sense that the staff is making that 28 recommendation, but that is not the way the Board || Vol. Pg.756  HALTON HILLS HYDRO/PETERBOROUGH 1 necessarily is looking at it". 2 My comment really referred to your appendix to 3 Procedural Order No. 4 which listed issues, but the 4 issues did not seem to list as issues the submissions 5 that you just heard from the Alliance, some of the ones 6 I have made and also the ones in the submissions by Mr. 7 Adamson on behalf of the G-10 group, such as whether 8 yardsticking would be better and a number of other very 9 fundamental issues. 10 I take it -- and I didn't mean to suggest that 11 this was a criticism -- I take it that the Board is 12 still open to all of those suggestions which is why I'm 13 here making them. 14 MEMBER ZERKER: That is absolutely the case. 15 I simply want to put that on record so that you and your 16 clients understand that that is the way it is. Okay? 17 MR. ROMAN: Thank you, Dr. Zerker. 18 MEMBER ZERKER: In the context of that comment 19 that I made, I bring you to the point further down on 20 your first page where you say that the OEB has the 21 discretion to use any reasonable method. Yes, that is 22 exactly what we are doing here. Not only are we doing 23 it here, but we are -- as you are yourself aware from 24 all the different submissions, the complexities of the 25 situation, given the legal requirement imposed on the 26 Board to start with, and then the nature of the industry 27 itself in this transition and the transformation should 28 suggest to you that we are indeed taking that very || Vol. Pg.757  HALTON HILLS HYDRO/PETERBOROUGH 1 seriously. 2 Now, I'm not a lawyer and you are, so let me 3 ask you about your position about commercialization. 4 You take the position that commercialization is not an 5 identity with competition. 6 MR. ROMAN: With corporatization? 7 MEMBER ZERKER: No. You are saying that when 8 the White Paper suggests that the utility should be on a 9 commercial footing, that that is not a legal 10 requirement, that is a proposal in the form of a 11 government policy rather than a legality, and that it 12 does not -- one should not by that, even if that is a 13 government policy, assume that that necessarily means 14 that we move into a for-profit operation as long as it 15 is in a -- the shares are held by a municipality. That 16 is what you are suggesting to us? 17 MR. ROMAN: Not quite. I am suggesting 18 that -- there are really two points I'm making here. 19 First of all, this was not a point I made before but 20 it's a point that theory caused me to think I should 21 have made, which is that there is a difference between 22 the White Paper and your legislation. 23 The White Paper preceded your legislation. It 24 was an announcement of government policy prior to the 25 announcement of government policy that is in the 26 legislation. When looking at what your duties are, your 27 marching orders as a Board come from the Act, not from 28 the White Paper. || Vol. Pg.758  HALTON HILLS HYDRO/PETERBOROUGH 1 MEMBER ZERKER: Exactly. 2 MR. ROMAN: So I'm not suggesting that the 3 White Paper has any relevance at all here apart from 4 possibly helping you to interpret what the legislation 5 might mean by way of general background, that the most 6 recent statement of the legislature on the point is the 7 legislation not the White Paper. 8 The only reason why I raise the White Paper is 9 because a number of people quoted from it because it 10 used the expression "commercialization". 11 I am not sure what that expression meant in 12 the White Paper and I don't think that the word 13 "commercialization" has any precise meaning in any 14 event, and it means different things to different 15 people, which is perhaps why we shouldn't use it all 16 that much. I say that even though I have used it. But 17 I have used it because others have. 18 What I'm really saying to you is that the 19 legal duty to corporatize should not be equated to the 20 legal duty to try to earn a maximum return; in other 21 words, to operate as a commercial operation that 22 operates for profit. "Commercialization" can mean at 23 least two things. One is to operate as efficiently as a 24 commercial enterprise and the other is to operate on a 25 profit maximizing basis. 26 I think that the White Paper and the 27 legislation intended the former to be a goal, but the 28 latter not necessarily to be a goal. It is up to the || Vol. Pg.759  HALTON HILLS HYDRO/PETERBOROUGH 1 choice of the municipal council as to whether they wish 2 to be profit maximizers or whether they wish to sell 3 power at cost. By "cost" I do not necessarily mean to 4 include in that definition of "cost" the economists' 5 classic definition of "cost" which includes the cost of 6 equity capital, because municipalities tend to treat 7 that cost as zero. There is nothing in the law that 8 says that that is wrong. You don't have to interpret 9 your legislation the way the economic theory that was 10 developed in a private ownership setting would suggest. 11 MEMBER ZERKER: So what you are telling me -- 12 and this is what I am trying to clear up because we have 13 had some legal advice from other intervenors -- you are 14 saying that there is no legal requirement to operate at 15 a profit? 16 MR. ROMAN: That's correct. 17 MEMBER ZERKER: Okay. That is all I wanted. 18 I won't dispute your opinion because I have no expertise 19 in this area. I just want to be clear that that is what 20 you are telling me. Okay? 21 MR. ROMAN: That's correct. 22 MEMBER ZERKER: Then I would like to go down 23 to your goals for PBR. Down below there you say that 24 PBR is unnecessary to achieve the second goal which is 25 to protect consumers from excessive rates. Then you 26 have in brackets there: 27 "(Ontario Hydro prevented excessive rates 28 without this)". || Vol. Pg.760  HALTON HILLS HYDRO/PETERBOROUGH 1 Would you agree that Ontario Hydro has 2 accumulated billions of dollars in debt that we now have 3 to deal with through the legislation on how we pay that 4 back? 5 MR. ROMAN: Absolutely. Now that you ask the 6 question, though, it strikes me that there may have been 7 an ambiguity in what I was I saying there. When I said 8 "Ontario Hydro prevented excessive rates without this", 9 I was not referring to Ontario Hydro's own rates. I was 10 referring to Ontario Hydro in its capacity as a 11 regulator of the MEUs. What I meant was that Ontario 12 Hydro prevented the municipalities from having excessive 13 rates without subjecting the municipalities to PBR. 14 So I apologize if that was read the other way. 15 That was not the way it was intended. 16 MEMBER ZERKER: I take that and I understand 17 what you are saying. But, on the other hand, Ontario 18 Hydro's debt from the point of view of the system as a 19 whole has to be regarded, even from the point of view of 20 an individual MEU, as having been provided with the 21 benefits of investment that the MEU did not have to do. 22 That debt has accumulated and is therefore a part of the 23 rationalization of the lower rates. 24 MR. ROMAN: No question. No question. 25 MEMBER ZERKER: Okay. 26 Then I would take you to the next point -- I 27 really don't want to get into a debate. I just simply 28 want to clarify a lot of things that you are saying. || Vol. Pg.761  HALTON HILLS HYDRO/PETERBOROUGH 1 One of the things you say, in the next point, 2 is that the TTC, you know, doesn't have a return on 3 equity, if it does it is -- well, in any case, it is 4 negative. 5 MR. ROMAN: It may well be. 6 MEMBER ZERKER: We should really be clear on 7 this. That debt of Ontario Hydro was under a policy 8 that permitted a public service monopoly to be paid for 9 through a government taxation and so is the TTC. What 10 we are into now is -- would you agree that we are into a 11 new regime now where the government has decided that 12 they no longer will pay for this cost, overhead cost and 13 ongoing cost through taxation? 14 My point is, can you make a comparison between 15 a system and an agency and a service where the 16 government continues to pay for its surplus expenditure 17 or revenue losses -- let's put it that way, which is a 18 better way -- through taxation and one which we are now 19 into where the government says "We won't do this any 20 more"? 21 MR. ROMAN: I understand the difference 22 conceptually, but I don't think they have actually 23 achieved that. 24 MEMBER ZERKER: No. But is that not what we 25 are supposed to be doing here? 26 MR. ROMAN: I would submit no. 27 MEMBER ZERKER: Why? 28 MR. ROMAN: Because, again, there is nothing || Vol. Pg.762  HALTON HILLS HYDRO/PETERBOROUGH 1 in your legislation and nothing in government policy 2 that says that the way you try to ensure that wires 3 companies, whether it is servco or a municipal wires 4 company, does not get off the rails is by means of PBR. 5 MEMBER ZERKER: No, no. I agree that -- 6 MR. ROMAN: You should try and ensure that 7 they do not get off the rails. You should try and 8 ensure that we don't get more stranded debt. 9 But I would submit to you, and this is perhaps 10 a more direct answer to your question, if we had had PBR 11 for the last 10 years, I don't think that that would 12 have prevented Ontario Hydro's stranded debt from being 13 what it is now either. 14 MEMBER ZERKER: Okay. Leaving aside the issue 15 for the moment about PBR, are we not into at this point 16 a program that says, in effect, that this industry is 17 going to have to pay for itself through rates, not 18 through taxation? 19 MR. ROMAN: That's the theory, yes. 20 MEMBER ZERKER: Yes, okay. 21 That is why I say it is really unfair to make 22 a comparison between that and the system where the 23 government, in the City of Toronto or wherever, is still 24 prepared to say: Okay, it is a necessity. It's a 25 service that is a necessity and whatever difference will 26 arise taxation will have to undertake to cover it. But 27 we are no longer doing that. 28 MR. ROMAN: But I'm not making that point. || Vol. Pg.763  HALTON HILLS HYDRO/PETERBOROUGH 1 I am only making the point that the technique 2 of regulating a return on equity is not necessarily the 3 best technique for preventing the kinds of problems that 4 have happened in the past. 5 MEMBER ZERKER: Okay. I take that. 6 MR. ROMAN: I am saying you should regulate 7 them, definitely, and you should try to ensure that they 8 internalize their costs -- 9 MEMBER ZERKER: Right. 10 MR. ROMAN: -- rather than dumping them onto 11 the taxpayer. 12 MEMBER ZERKER: Right. 13 MR. ROMAN: But whether you use a -- 14 MEMBER ZERKER: Well, we have to anyway -- 15 MR. ROMAN: That's right. 16 MEMBER ZERKER: -- because the government said 17 we have to. 18 MR. ROMAN: That's right. 19 MEMBER ZERKER: Yes. 20 MR. ROMAN: But how you do that is really the 21 question. 22 MEMBER ZERKER: Right. And that is what we 23 are all here for is to find out how to do that. 24 On the next page of your -- 25 MR. ROMAN: I'm sorry, if I could just add. 26 How you regulate a government-owned entity, 27 however, is crucial because they don't necessarily 28 respond the same way as privately owned entities to the || Vol. Pg.764  HALTON HILLS HYDRO/PETERBOROUGH 1 same mix of incentives and disincentives. That's really 2 the point. 3 MEMBER ZERKER: Mr. Roman, that is exactly my 4 next question. 5 MR. ROMAN: Okay. 6 MEMBER ZERKER: You couldn't have timed it 7 better. 8 Your point is that the economic -- PBR is not 9 particularly good at achieving the third goal, which is 10 economic efficiency in publicly owned entities. 11 They are publicly owned at this moment, but 12 does the Board not have to foresee the opportunities 13 that are out there, given the legislation and given the 14 objectives of the government, that these will not -- or 15 many of the utilities will not be publicly owned, they 16 will become private entities, and that we have to in 17 fact take into account a system of regulation that will 18 deal with both the public and the private? 19 MR. ROMAN: I agree. 20 But the solution to that is to have two 21 methods of regulation, one for privately owned and one 22 for publicly owned. If you try to use the 23 one-size-fits-all approach, you can create perverse 24 incentives. 25 Just by way of example, a utility that wants 26 to sell would be better off now not laying off people 27 that it otherwise would have laid off, making sure that 28 employees who would otherwise retire hang around instead || Vol. Pg.765  HALTON HILLS HYDRO/PETERBOROUGH 1 of allowing them to retire, of bulking up on inventory 2 of light poles and wires, and generally being as 3 inefficient as possible before the PBR comes in, because 4 when they privatize the private owner will be able to 5 make the savings, and the private owner will be able to 6 benefit under PBR, and the private owner will pay the 7 council a premium for that. 8 In other words, you are creating a set of 9 numbers or a numbers game which, if the utility wants to 10 play it right, creates the incentive to be as 11 inefficient as possible before this cuts in. That, I 12 would suggest, is a perverse incentive. 13 So yes, you need to do that, but you need to 14 do that very carefully and to make sure that the 15 constellation of carrots and sticks is right. 16 MEMBER ZERKER: We have two different kinds of 17 sets of rules and methodologies, as far as you -- 18 MR. ROMAN: You will have to, because they 19 respond to different sets of rules and methodologies. 20 MEMBER ZERKER: You cannot conceive of a 21 municipality that is the owner of a utility, owns the 22 shares of the utility, responding to the same kind of 23 stimuli, economic stimuli as a private enterprise? 24 MR. ROMAN: I can't go so far as to say it is 25 inconceivable, but I can go so far as to say it is 26 highly improbable because the political incentives on 27 the municipality are, as I have suggested, not to 28 overtly increases prices in order to send 45 per cent of || Vol. Pg.766  HALTON HILLS HYDRO/PETERBOROUGH 1 the money to the province. I don't think mayors get 2 re-elected for doing that, or at least I don't think 3 they think they get re-elected for doing that. 4 MEMBER ZERKER: Which I think you are talking 5 about that in the next point, about that very issue, are 6 you not? 7 MR. ROMAN: Yes. 8 MEMBER ZERKER: You are the lawyer. Does the 9 Board have any options in regard to how the debt gets 10 paid? I mean, are we not regulated by the Act that says 11 that in lieu of taxes -- taxes are calculated, as you 12 know, according to not the Board's rules and not by any 13 municipality's rules but by the province and the federal 14 government -- so that in lieu of taxes that has to go to 15 pay back what has accumulated in debt in the electricity 16 industry. 17 MR. ROMAN: That is the legislation, but the 18 Board has no legal role to play in relation to that. 19 People pay -- 20 MEMBER ZERKER: No, we don't. 21 MR. ROMAN: They pay their taxes whether you 22 are here or not -- 23 MEMBER ZERKER: Right. 24 MR. ROMAN: -- and your job isn't to compel 25 them to pay their taxes. That is someone else's job. 26 But you will have to take that into account, 27 of course, in the regulatory mechanisms you set up to 28 ensure that you are working in a manner that is || Vol. Pg.767  HALTON HILLS HYDRO/PETERBOROUGH 1 consistent with the disincentive created by the payment 2 in lieu system to earn profits. 3 MEMBER ZERKER: I see your argument. 4 Well, I am going to let my colleagues go on 5 from here. 6 THE PRESIDING MEMBER: Mr. Vlahos? 7 MEMBER VLAHOS: Thank you, Mr. Chairman. 8 Good morning, Mr. Roman. 9 MR. ROMAN: Good morning, sir. 10 MEMBER VLAHOS: Mr. Roman, I followed this 11 discussion with interest. 12 I guess my question is: If it was the intent 13 of a government that perhaps ownership should play a 14 role in regulation going forward, wouldn't there be some 15 indication, if not direction, or at least a hint that 16 that ought to be the case and it should be considered by 17 the regulator? 18 MR. ROMAN: I'm not sure I understand what you 19 mean by "ownership should play a role". 20 MEMBER VLAHOS: Well, you tend to 21 differentiate between private ownership and co-ops. 22 MEUs with ownership as currently exists are now 23 changing. 24 My question is: If that is what was intended 25 wouldn't we have some kind of a hint somewhere, if not a 26 direct direction from the government that the Board 27 ought to consider those different circumstances? 28 MR. ROMAN: I would put the question the other || Vol. Pg.768  HALTON HILLS HYDRO/PETERBOROUGH 1 way, sir. 2 If the government was going to equate the 3 incentives for privately owned utilities with the 4 incentives for publicly owned utilities there would have 5 been more than a hint of that in the legislation. You 6 would have been directed in the legislation to treat 7 publicly owned utilities as if they were privately owned 8 if the government thought that that was important. 9 But they didn't. What they have given you is 10 a broad discretion. What they have said to you is: We 11 trust your judgment to figure out the best way to do 12 this. We are not going to tell you how to do this at 13 all. We will let you do it whichever way you think is 14 the way that results in rates that are just and 15 reasonable. 16 Some utilities, if you look out west for 17 example, some regulators in their legislation have been 18 told with great precision that they have to allow a rate 19 of return on equity calculated in such and such a manner 20 with great detail. 21 You have not been told that. You have been 22 given a broad discretion to do whatever you think is 23 reasonable, so there is no hint either way. 24 That is why I would suggest to you that if the 25 legislature had intended to constrict the exercise of 26 your discretion in a manner that forced you treat 27 publicly owned utilities as if they were privately owned 28 utility, which to me is a real stretch, then the || Vol. Pg.769  HALTON HILLS HYDRO/PETERBOROUGH 1 legislature would have told you to make that stretch 2 instead of giving you the discretion not to stretch 3 yourself that way. 4 MEMBER VLAHOS: No, I appreciate turning the 5 question around. I appreciate your point. 6 I just want to move on on this. 7 You seem to put a lot of emphasis on the lack 8 of definition of what is commercialization. I guess I 9 have sat in a number of hearings, and I'm sure so have 10 you, Mr. Roman, and there are a lot of terms that are 11 not always necessarily defined but nevertheless we find 12 a way to deal with them as we move forward because they 13 make sense from a commonsense point of view. 14 You talked about they economic efficiency part 15 of it. Although you won't find a clear definition I 16 want to take you to the general intent of the Act as 17 spelled out. I'm sure you have read those. You are 18 familiar with those. 19 MR. ROMAN: A few times. 20 MEMBER VLAHOS: It talks about the 21 responsibility given to this Board is to facilitate a 22 smooth transition to competition, okay. It talks about 23 promoting economic efficiency in the generation, 24 transmission and distribution of electricity. Here we 25 are talking about distribution. It talks about 26 facilitating the maintenance of a financially viable 27 electricity industry. 28 So those are the certain economic principles || Vol. Pg.770  HALTON HILLS HYDRO/PETERBOROUGH 1 here, economic efficiency principles. I just want to 2 take you to the notion of not pricing something 3 appropriately. Wouldn't that be inefficient? 4 MR. ROMAN: I participated in the Board 5 hearing some years before, called HR-5. That hearing 6 went on for two years. We spent two years discussing 7 what economic efficiency meant. My recollection of it 8 is that there are at least 29 different definitions of 9 economic efficiency. 10 So it doesn't take me very far down that road 11 either. 12 When I look at those kinds of definitions, and 13 if I can take myself back to those days, what we are 14 really left with in this Board is a discretion to 15 determine what we mean by that as well. I would suggest 16 to you that a number of definitions come to mind, such 17 as higher output at lower cost, less wasted resources, 18 those kinds of things. 19 Those are all good things, but the problem 20 with it is that they don't tell you whether the outputs 21 that are being produced are the right outputs. 22 For example -- and this goes back to a 23 question that Dr. Zerker asked on the last panel about 24 reliability. One of the questions that nobody knows the 25 answer to yet -- and I had the pleasure of working on a 26 paper on this recently -- is: How much reliability is 27 enough? 28 It is possible to gold plate a system and || Vol. Pg.771  HALTON HILLS HYDRO/PETERBOROUGH 1 produce too much reliability or too little, and 2 different customers have different demands for different 3 degrees of reliability. 4 How should you set the average? At the 5 highest common factor, the lowest common denominator, or 6 somewhere in between? All of these qualitative factors 7 come into it. 8 So when we talk about commercialization, you 9 won't find the word commercial or commercialize anywhere 10 in the act. What you will find, as you have correctly 11 pointed out, Mr. Vlahos, is some suggestion that what we 12 should be concerned about is a better and more efficient 13 use of resources. And I don't dispute that. 14 But quantifying that and looking at also what 15 the right outputs are is a difficult question. If it 16 wasn't a difficult question, all of you members of the 17 Board or all of the people who appear before you could 18 be replaced by a computer. 19 So there are lots of qualitative issues in 20 there as well which require judgment. Really, what you 21 are required to do is exercise your judgment with the 22 assistance of certain techniques which aid you. 23 My suggestion to the Panel thus far has been 24 that both techniques should be carefully selected to 25 make sure that they are relevant to the job at hand and 26 that they are themselves efficient at achieving the 27 objective of efficiency. 28 If not, then the Board will be heading off in || Vol. Pg.772  HALTON HILLS HYDRO/PETERBOROUGH 1 the wrong direction. 2 But none of that leads you in the direction or 3 requiring or forcing municipalities -- and you have no 4 jurisdiction to force them, I can tell you that -- to 5 seek to maximize their returns. 6 If a utility chooses not to maximize its 7 returns, there is nothing you can do about it in the 8 act. You can set a cap, but I don't believe the Board 9 can say you must make no less than a 10 per cent return. 10 MEMBER VLAHOS: I appreciate that. I 11 appreciate that the PBR Handbook itself does not force a 12 system to price to the cap. 13 MR. ROMAN: That's right. 14 MEMBER VLAHOS: It provides the flexibility to 15 do so, and a municipal system has the opportunity to 16 price below that. 17 Of course, there are certain economic 18 efficiencies that we talked about and certain financial 19 considerations. But leaving aside what the system may 20 choose to do while it still remains under public 21 ownership as opposed to private ownership, you don't see 22 the distinction of capital employed by a private versus 23 a public entity, the distortions that will come out of 24 pricing that same unit in a different way? 25 You don't see any market distortions? 26 MR. ROMAN: I do, but I would submit to you 27 that that distortion may be less than another 28 distortion. If we are looking at distortions, let's || Vol. Pg.773  HALTON HILLS HYDRO/PETERBOROUGH 1 look at them in context. 2 There is another distortion which now has been 3 created by the 45 per cent tax. You are forcing a 4 utility which before has never paid tax to pay tax. 5 That is the price of earning a dividend. That is the 6 price of making a profit. 7 So you are introducing two changes 8 simultaneously, and each one will have an impact. 9 When I say "you", I don't mean the Board; I 10 mean the legislation. 11 The Board can't deal with the 45 per cent tax. 12 You didn't introduce that. But when you are trying to 13 work out what your incentives are, you should take into 14 account the disincentive that is elsewhere in the 15 legislation by the 45 per cent. That is one point. 16 The other point is that at the other end of 17 it, let's say that the utility does earn a dividend. 18 What does it do with that dividend? It takes that money 19 and it can either at the end of the year, as co-ops do, 20 give the utility customers a rebate; or it can take that 21 dividend out in the form of lower rates. 22 Well, an economically rational advisor would 23 advise a municipality to take the money out beforehand 24 in the lower rates rather than send 45 per cent of it to 25 the provincial government. So you are accomplishing the 26 same thing at less cost and with less distortion. So if 27 we are looking at distortions, let's compare 28 distortions. || Vol. Pg.774  HALTON HILLS HYDRO/PETERBOROUGH 1 MEMBER VLAHOS: Okay. But I think we are on 2 the same wavelength when I say that -- I sense from your 3 points that a public utility will price less. It is 4 disadvantaged, especially now because of what you view 5 as a conflicting signal because they have to pay taxes; 6 therefore, why would I raise my rates when I can raise 7 my money from somewhere else? I don't have to make the 8 federal coffers richer. 9 MR. ROMAN: That's right. 10 MEMBER VLAHOS: All this argues for lower 11 rates for the municipally owned systems. The 12 flexibility is there. That is my point; the flexibility 13 is there. 14 I want to take you back to the point you had 15 with Dr. Zerker, which is that from the Board's point of 16 view we tried to set the stage going forward. Shouldn't 17 we have in mind as an end state a utility that is 18 privately owned, the same way as gas? 19 If a system is owned by a municipality, they 20 can price below that. That is their prerogative. 21 MR. ROMAN: Well, what you seem to be saying 22 is that you ought to make an assumed forecast that the 23 end state will be privatization. No? 24 MEMBER VLAHOS: I am suggesting -- and that is 25 a question that I had of many parties. Shouldn't that 26 be a working assumption for the Board? 27 MR. ROMAN: I would submit that it should not. 28 The Board should not make any forecast on that || Vol. Pg.775  HALTON HILLS HYDRO/PETERBOROUGH 1 issue, but again retain your own flexibility. Those 2 municipalities that intend to privatize and will 3 therefore be moving from a system of incentives where 4 there is no incentive to profit maximize to a system 5 where there will be an incentive to profit maximize will 6 be creating, in future, a conflict between their 7 shareholders and their customers, or a potential 8 conflict, which the Board must resolve for the sake of 9 protecting the customers. 10 Until they move to that, however, you ought 11 not to assume that it is broken and needs fixing. Until 12 they move to that, you ought to deal with them, I would 13 submit, the way they are now and not the way they might 14 be at some hypothetical future. 15 For all you and I know, Mr. Vlahos, ten years 16 from now not one utility in Ontario may be privatized. 17 Alternatively, they may all be privatized. Neither of 18 us knows the answer to that now. 19 If you assume that it is going to be all one 20 way rather than all the other way and you set up a 21 system of incentives and disincentives for that, you may 22 be constructing a mechanism that is totally 23 dysfunctional in relation to the status quo. That, I 24 would submit, is where the danger lies. 25 MEMBER VLAHOS: Just to complete that point, 26 it is my reading of the Handbook that it does not force 27 a utility to go to the maximum. You would have to agree 28 with me on that. || Vol. Pg.776  HALTON HILLS HYDRO/PETERBOROUGH 1 MR. ROMAN: Yes. And I am not being critical 2 of it by suggesting that it is. I am just suggesting 3 that it assumes that the right to go to the maximum is a 4 valuable right, and it assumes that that will serve as 5 an incentive to make everybody more efficient. 6 My suggestion to you is that those 7 municipalities who don't care whether or not they can go 8 to the maximum and have no intention of going to the 9 maximum ever are going to find the whole PBR mechanism 10 irrelevant. 11 MEMBER VLAHOS: Based on your experience, 12 Mr. Roman, I am sure you have read the original cases on 13 maximizing profits or rate of return that should be 14 afforded to the provider of capital, going back to 15 the -- was it the Blumfield case? 16 MR. ROMAN: Yes. 17 MEMBER VLAHOS: It seems to me that that 18 matter has been settled. 19 If there is a public ownership entity that 20 wishes to earn the maximum, there is legal precedent 21 that it can do so. 22 MR. ROMAN: It could do so, not just because 23 of the Blumfield case which, like all the other cases, 24 was decided in the U.S. in the context of privately 25 owned utilities, but for other reasons. 26 The U.S. reasoning in those cases is based on 27 the U.S. Constitution and the legal idea that you cannot 28 expropriate the property of shareholders by allowing || Vol. Pg.777  HALTON HILLS HYDRO/PETERBOROUGH 1 them an unreasonably low return. That reasoning is part 2 of what does not apply to the publicly owned utilities 3 because you are not expropriating anyone's capital 4 because they don't necessarily want to make the maximum 5 return. 6 I agree with you that you are not doing 7 anything unlawful by creating the permission to do that. 8 You can give them the permission to do that. My 9 submission to you though is that it may not achieve 10 anything if you do do that. 11 At least for the smaller municipalities, the 12 cost and complexity of dealing with these formulae and 13 the side effects that this medication may carry with it 14 are things that you might want to consider seriously. 15 If you are not creating huge benefits on the side but 16 you may be creating wrong incentives on the other side, 17 then the net effect of what you are doing may not be 18 very helpful to the situation of the MEUs in Ontario as 19 they are today. 20 MEMBER VLAHOS: Just a last question then. 21 The mechanics of the regulatory regime as you see it for 22 the municipally owned systems, your suggestion is that 23 there ought to be a guideline only and that guideline 24 would prescribed what, the maximum rate of return? 25 MR. ROMAN: What I am suggesting here is that 26 if the Board accepts my submission that they should wait 27 and think about this a whole lot more before doing it, 28 then the question arises, and I think one of you asked || Vol. Pg.778  HALTON HILLS HYDRO/PETERBOROUGH 1 this question of the last presenters, what do we do in 2 the meantime? 3 I think it was Mr. Dominy's question "What 4 would you think we should do in the meantime because we 5 can't do nothing in the meantime?". My suggestion for 6 that or my answer to that is no, you can't do nothing 7 but what you can do is set a cap of 9.7 or 10 per cent 8 and then say "If anybody wants higher than that cap, 9 come and ask us and tell us why you need that". 10 That may be all you need to do now or perhaps 11 for the next five years if no one wants anything in 12 excess of that cap. 13 MEMBER VLAHOS: I am looking even further 14 ahead on that, beyond the interim. The mechanics of 15 your suggestion would be what? There would be some 16 general guidelines out there to be followed by the 17 municipalities. You are not saying that this Board will 18 have an exercise at all over those systems, over the 19 pricing of those services of municipally owned systems. 20 MR. ROMAN: Well, you could take the position 21 of regulatory forbearance vis-a-vis the municipal 22 utilities that are publicly owned. I see nothing wrong 23 with that position unless and until you come to a 24 situation where you see that there is in fact a problem. 25 A lot of the work that has been done on this 26 PBR Handbook may have anticipated the existence of a 27 problem, but my impression of what Ontario Hydro's 28 regulation was, and I don't suggest that Ontario Hydro || Vol. Pg.779  HALTON HILLS HYDRO/PETERBOROUGH 1 was necessarily a heroic model, but my impression of 2 their regulation was that it was pretty much 3 light-handed. 4 I have also seen the regulation of telephone 5 companies in this province that are municipally owned. 6 The regulation there was light-handed. They ended up 7 with local rates that were half the rates of Bell 8 Canada. 9 There is something to be said for the 10 suggestion that if it isn't broken, don't fix it. 11 MEMBER VLAHOS: Mr. Roman, I am just seeking 12 some assistance here from Mr. Dominy. I am sure you 13 know it. I thought the issue of forbearance, it was 14 quite restrictive as to under what circumstances the 15 Board could forbear such as has to be -- I can't recall 16 the words. 17 MR. ROMAN: Technically you're right. 18 MEMBER VLAHOS: A workable competition or 19 something to that effect. 20 MR. ROMAN: I used the wrong term. I 21 shouldn't have used the term "forbearance". Let me try 22 it again. 23 The manner of exercising the Board's 24 discretion as to when rates are just and reasonable is 25 up to you. It follows from that that you don't need to 26 have a formula and you don't need to have a cap. 27 You could do, for example, what's been done in 28 airlines and railways, which is a somewhat deregulated || Vol. Pg.780  HALTON HILLS HYDRO/PETERBOROUGH 1 business by regulatory agencies that have no formal 2 ratemaking powers as such to operate on a complaint 3 basis. 4 That is to say if somebody is going to argue 5 that someone's rates are too high, let them come to you, 6 let them complain and say "The rates are too high". I 7 would submit if you wanted to do that, nobody would be 8 able to challenge the legality of that. You may not 9 think that's good policy, but you could certainly do it. 10 You could do that for a year or two or as long as you 11 want. You may find that no problems are created by 12 that. 13 MEMBER VLAHOS: I promise, Mr. Chairman, this 14 is my last question. 15 I guess one has to look carefully at the 16 legislation the way it currently reads and see what is 17 possible, what is not, what is doable, what is not. I'm 18 just looking at section 78(2). It says: 19 "No distributor shall distribute 20 electricity or meet its obligations under 21 section 29 of the Electricity Act except 22 in accordance with an order of the 23 Board." 24 What would the order say? 25 MR. ROMAN: That would refer to the standard 26 supply option, if I recall correctly. I don't have my 27 Act in front of me. 28 MEMBER VLAHOS: And the rates. || Vol. Pg.781  HALTON HILLS HYDRO/PETERBOROUGH 1 MR. ROMAN: Pardon me? 2 MEMBER VLAHOS: And the rates. The section 3 has to do with rates. 4 MR. ROMAN: What you need to do is when you 5 create the permanent licences, you can put rate 6 provisions in the permanent licences. That would 7 qualify also as an order of the Board, or you could make 8 a separate order at the time or as part of the order 9 granting the permanent licence. 10 You could put in there a condition that the 11 rates that apply or the rates that will apply in future 12 will be the same rates as they are now or such rates as 13 the municipality may from time to time submit to the 14 Board as being its proposal for just and reasonable 15 rates. 16 When proposals are received by the Board to 17 change rates, there could be public notice given that 18 such a proposal has been received, an opportunity for 19 the public, which is the ratepayers in that community, 20 to make objections to it. 21 I used the word "ex ante" and maybe that was a 22 mistake because that's Latin, but what I meant by that 23 was that the Board is not obligated to have a procedure 24 whereby somebody must come to you and first seek 25 approval. The Board can grant approval as you go along, 26 unless somebody objects. 27 MEMBER VLAHOS: Thank you, Mr. Roman. I 28 enjoyed your presentation, including the colourful || Vol. Pg.782  HALTON HILLS HYDRO/PETERBOROUGH 1 metaphors of mousetraps, and nailing Jell-O to the tree, 2 breaking the wood. 3 Thank you very much. 4 MR. ROMAN: Thank you. 5 THE PRESIDING MEMBER: I have a quick 6 question, Mr. Roman. That is my understanding of the 7 history of Ontario Hydro regulations is that Ontario 8 Hydro itself had a Rate Handbook that they sent out 9 every year, I believe, some sort of guidance to the 10 utilities. 11 MR. ROMAN: That's correct. 12 THE PRESIDING MEMBER: On how to prepare their 13 rates, et cetera. So you have a situation existing 14 where the utilities "may be expecting some guidance as 15 to how they may proceed" and "they may be expecting some 16 form of Handbook". 17 The question is how do you deal with that in 18 the context of your proposal? 19 MR. ROMAN: First of all, Mr. Chair, I 20 wouldn't assume that the municipalities were all 21 necessarily grateful for the Handbook they received from 22 Ontario Hydro. Nor would I assume that they found the 23 guidance in there helpful. I have been involved with 24 some of them who have had serious arguments with Ontario 25 Hydro about how those guidelines were applied. 26 I don't mean to suggest that a Handbook is de 27 rigueur, but the Board could, of course, offer 28 guidelines which would be in the form of suggestions as || Vol. Pg.783  HALTON HILLS HYDRO/PETERBOROUGH 1 to what would be an efficient rate structure, what kind 2 of information the Board would like to receive from MEUs 3 over the years to improve the quality of the database 4 that's available for monitoring purposes for the Board 5 and what the Board would regard as indicators of an 6 efficient and fair rate structure. 7 For example, there's a lot of important work 8 in the Handbook that deals with cost of service studies 9 and with the rates as between different customer 10 classes. Those kinds of issues, I would submit, should 11 be dealt with because they have been ignored for too 12 long. If the Board wished to include those kinds of 13 issues in the Handbook, or in any Handbook of some sort, 14 I think that could be very useful. 15 The Board could also use its current PBR 16 handbook as suggestions as to what MEUs could adopt 17 voluntarily, but not make it compulsory. 18 Those MEUs who wanted to adopt that Handbook 19 or some variation of it could do so. I would have no 20 quarrel with that. The only concern becomes when it 21 becomes compulsory and when it may not be pushing the 22 right buttons in the MEU. 23 THE PRESIDING MEMBER: Ms Kwik, you are 24 looking at me. Have you a clarification you wish to 25 make on that, as to the Handbook? 26 MS KWIK: No, thank you. 27 THE PRESIDING MEMBER: But when you come to 28 your question, I think you said that you have a || Vol. Pg.784  HALTON HILLS HYDRO/PETERBOROUGH 1 guideline like the maximum ROE without an application 2 for higher returns, you would still anticipate that the 3 utility would submit for approval some form of rate 4 schedule? 5 MR. ROMAN: Yes. I would suggest that they 6 should submit some sort of rate schedule for a couple of 7 reasons. 8 One of them is the intergenerational versus 9 intragenerational equity issues; and the other is the 10 whole treatment of different customer classes because 11 there may now be all kinds of cross-subsidies built into 12 the system as between different customer classes, and to 13 return then to a question Mr. Vlahos put to me earlier, 14 this may be very inefficient because there may be 15 subsidies of one customer class which has 16 anti-competitive effect and you are supposed to 17 facilitate competition. 18 So I can see that there are important issues 19 along those lines. 20 THE PRESIDING MEMBER: Mr. Vlahos. 21 MEMBER VLAHOS: Just something that occurred 22 to me that I wanted to ask you before. 23 If there is that flexibility for municipal 24 systems to price below a cap or earn a return that 25 doesn't get close to the authorized, and there has been 26 some discussion over the last few days about the 27 symmetry, or right now the lack of symmetry when it 28 comes to the rate of return achieved, and some parties || Vol. Pg.785  HALTON HILLS HYDRO/PETERBOROUGH 1 would want the Board to have the symmetry applied to 2 the -- you know, if you don't achieve the rate of return 3 authorized, then you can bank it or you can average it 4 or you can do all kinds of things with it. I just want 5 to make sure that there is no inconsistency here or that 6 at least there is no mix up of what we are trying to 7 achieve if the municipal system does not wish to earn a 8 rate of return that is maximum, and if we do allow for 9 some symmetry below the dead band, as we would have, 10 say, above the dead band. I see a problem there. 11 Do you get my question? I'm not sure I have 12 articulated it well. 13 MR. ROMAN: I know your question, but I think 14 you need to look at the question of why utilities want 15 to be able to bank this. It is a little bit like tax 16 losses and why people want to bank those. 17 The game that is being played here already 18 anticipates the numbers games and the incentives that 19 are built into PBR. Obviously, if I am going to sell my 20 utility and I can theoretically earn, by cost cutting, a 21 very nice bunch of returns year in and year out but I 22 don't make those returns, I can obtain a very nice 23 spelling price if I have all those returns built up in 24 the bank as a reserve. So I can see the incentive to do 25 that. That is at least one incentive to do that. 26 The other I suppose is to balance out the lean 27 years versus the fat years because investment in 28 electricity equipment, which has a very long life || Vol. Pg.786  HALTON HILLS HYDRO/PETERBOROUGH 1 expectancy, is much longer than a one-year cycle and so 2 people may want to have the flexibility to invest in 3 equipment in lumpy ways because that is necessary, and 4 also to bank it in terms of potential future sales. 5 Nevertheless, I would suggest that that is 6 still a second-best position and those who make that 7 submission to you are doing so again on the assumption 8 that this whole scheme is going to be required the way 9 it is in the Handbook and in that case there are two 10 advantages to being able to bank them as I suggested. 11 If you do not impose it in that fashion, then 12 I would suggest that those people who have asked for the 13 right to bank it would probably say it doesn't matter 14 now because there is no penalty to not banking it as 15 there would be if it was imposed in that fashion. 16 THE PRESIDING MEMBER: Dr. Zerker had one more 17 question. 18 MEMBER ZERKER: I want to say that I 19 appreciate your bringing up issues having to do with the 20 existing PBR scheme and that we have to look seriously 21 at how you define a customer or the productivity factor. 22 You also have alerted me to something that I 23 was not too well aware of, which is that electricity is 24 not a homogenous product and I will have to learn 25 something more about what kind of differentiation occurs 26 in electricity products. 27 But I want to make the point that you make 28 when you are talking about contributed capital. It came || Vol. Pg.787  HALTON HILLS HYDRO/PETERBOROUGH 1 through with Mr. Vlahos, too. 2 You say: 3 "...if the Board intends to regulate by 4 assuming that maximizing return on equity 5 is the goal." (As read) 6 That is not an assumption either inherent in 7 the goals of the Board's objectives or in the PBR 8 scheme. It is not inherent to either one of us, either 9 the Board or the PBR scheme, because Mr. Vlahos has 10 already examined with you that the possibilities of not 11 maximizing profit are inherent in the PBR scheme as the 12 staff has proposed it. Okay? 13 Now then, you have given me some -- I get a 14 challenge when somebody says to me, as you did, that 15 there is no incentive for profit maximization amongst 16 municipalities. Immediately I started saying: Hmm, why 17 could there be no incentive for profit maximization? I 18 can think of a number of things. I say. "Let's see. 19 Well, it is possible that a municipality would want to 20 attract an industry that is labour intensive, not 21 capital intensive, does not use a lot of energy and 22 would be willing to raise rates rather than taxation to 23 give the benefit on the tax side." So I can think of 24 that as an incentive. 25 I mean, you can think of a variety of 26 combinations. I can think of a situation where a 27 municipality doesn't have to depend upon the vote of its 28 customers as political actors because the political || Vol. Pg.788  HALTON HILLS HYDRO/PETERBOROUGH 1 situation is such that they maybe don't have a competing 2 party that has a chance, therefore it would be a nice 3 way to get their revenue. I mean, there are lots of 4 reasons why I could -- and I haven't even put my mind to 5 it. 6 So the idea that there is no incentive for 7 profit maximization amongst municipally-owned utilities 8 is I think a little exaggerated -- 9 MR. ROMAN: In its defence I would submit that 10 there is in fact a disincentive, which is the 45 per 11 cent tax. When I said there was no incentive, I 12 suggested that there was no political incentive. Now, I 13 have never had to run for anything politically, but some 14 of the people that we represent have. 15 What I am conveying to you is their perception 16 that if the local newspaper picks up the story that the 17 mayor and the councillors have increased distribution 18 rates, then that raises questions as to why: Why have 19 you done that; and why have you done that when you don't 20 get to keep the money, when there are other ways you 21 could make money and you do get to keep the money? 22 So this is the point I was making earlier. 23 Now, to do with attracting industry, you could attract 24 industry to your municipality by giving them grants and 25 incentives of all sorts. One of those could be by 26 giving away electricity at a price that is lower than 27 the cost of that electricity. But that, I would submit, 28 is something the Board should be looking into -- not || Vol. Pg.789  HALTON HILLS HYDRO/PETERBOROUGH 1 through PBR, because that isn't going to detect that. 2 The way to detect that is to look at it by customer 3 class and perhaps in other more refined ways. 4 I can agree with you that the Board should 5 look at that question because that then means that other 6 customers are paying more than they should and 7 subsidizing the customers that are paying less than they 8 should, and that is a serious issue. But that issue is 9 not going to be resolved by putting an ROE cap on 10 through the PBR. That tool doesn't deal with that 11 issue. 12 I would submit that those municipalities that 13 want to create that kind of incentive are still not 14 trying to maximize their ROE. What they are doing is 15 they are redistributing income among customer classes 16 and that is a different issue. 17 MEMBER ZERKER: I could argue with you about 18 it, but that is not what we are here to do. 19 Thank you very much, Mr. Roman. 20 MR. ROMAN: Thank you. 21 --- Pause 22 MEMBER VLAHOS: Mr. Roman, we are trying 23 assess, I guess, one of the comments that you made that 24 the Board has to be mindful of a municipality 25 cross-subsidizing an industrial customer. That 26 cross-subsidization, I take it from your comments, will 27 come from the rest of the customers. 28 I'm just thinking it through now -- in the PBR || Vol. Pg.790  HALTON HILLS HYDRO/PETERBOROUGH 1 regime you have certain rates that you are starting 2 with, that is the going in rates, and we would assume 3 that those rates are cost-based, okay. 4 MR. ROMAN: Okay. 5 MEMBER VLAHOS: Then the PBR, the way it would 6 work is that you have now a change in your maximum price 7 going forward. 8 MR. ROMAN: Yes. 9 MEMBER VLAHOS: So that is how much you can 10 charge. That is the maximum. 11 Now, if the municipality chooses -- and there 12 is certain flexibility, limited flexibility that the 13 Handbook proposes, I think it is 5 per cent of the 14 change in the price cap going forward. But I think the 15 discussion was something more substantial than that in 16 terms of cross-subsidy. I think that is what the 17 comments intended. 18 I'm not sure to what extent this Board would 19 have that kind of information or would police that kind 20 of thing. If a municipality says: Well, I want to lose 21 money on this deal because there are other side benefits 22 I can have, you know, employment or what have you, then 23 are you suggesting that the Board should be policing 24 that kind of thing? And how? 25 MR. ROMAN: I don't think the Board can police 26 it directly, but -- or even necessarily on a one-shot 27 basis if it is small, but the Board, as I understand it, 28 like other regulators, has always looked at the question || Vol. Pg.791  HALTON HILLS HYDRO/PETERBOROUGH 1 of fairness to different customer classes, and many of 2 the debates in the gas hearings I have seen have always 3 been about different customer classes of different sizes 4 saying: We are not being fairly treated here. 5 Really all I am suggesting is that the same 6 philosophy or the same principles could apply to 7 electricity. 8 I don't think, on the one hand, you have the 9 jurisdiction to micro-manage utilities down to the point 10 of looking at every single deal they make with 11 everybody, but if there is a consistent pattern of one 12 customer class substantially subsidizing another, then 13 the Board may wish to do something about it. 14 I do mention by way of caution that 15 cross-subsidies are not always easy to detect and it is 16 not always clear how costs should be allocated as 17 between customer classes, and you certainly aren't going 18 to go to 250 municipal utilities and look at that on a 19 one-by-one basis. 20 MEMBER VLAHOS: Mr. Roman, I'm sorry to 21 interrupt you, but your assumption here is that you talk 22 about fairly treated, fair treatment and that one class 23 is cross-subsidizing the other. I'm saying that is 24 not -- the starting point is that the utility, this is 25 how much he can charge, okay, and the assumption here is 26 that whatever you started in with, the rates for 27 residential and the rates for the industrial are based 28 on some kind of a causation or a cost allocation of some || Vol. Pg.792  HALTON HILLS HYDRO/PETERBOROUGH 1 kind, okay. Make that assumption. 2 MR. ROMAN: Yes. 3 MEMBER VLAHOS: So moving forward, if the 4 utility wants to price under cost for a specific 5 customer or group of customers that money would not come 6 from the second class, from the residential, it will 7 come out of the pockets of the municipality. 8 MR. ROMAN: It may or may not. It depends 9 on -- 10 MEMBER VLAHOS: Well, it has to, because if 11 you are going in with rates, okay, that the combination 12 of those two rate groups gives you the maximum price you 13 can charge and that dictates your revenue requirement or 14 revenue generation, okay. Now, you take those rates and 15 then moving forward, and if the utility says: Well, 16 okay, I want to price this new Honda plant below cost, 17 how does that come out of the residential payer? That 18 is where I have difficulty following you? 19 MR. ROMAN: It doesn't in the next day 20 necessarily, but in the long run if somebody is priced 21 below cost then the loss on that customer has to be made 22 up somewhere. 23 MEMBER VLAHOS: All right. So for the 24 duration of this first generation plan that is not an 25 issue. Then the issue will become so when you revisit 26 the plan for the next generation? 27 MR. ROMAN: If we are into the forced 28 assumption that the rates are cost based now, that is || Vol. Pg.793  HALTON HILLS HYDRO/PETERBOROUGH 1 correct. 2 MEMBER VLAHOS: Okay. Thank you. 3 I think I have it. Thank you. 4 THE PRESIDING MEMBER: Thank you very much. 5 MS KWIK: Mr. Chair, there is a matter of 6 procedure that I would like to bring up. 7 Ottawa Hydro has confirmed that they will not 8 be making an oral submission. 9 THE PRESIDING MEMBER: Thank you. 10 Thank you, Mr. Roman. 11 Thank you for your interesting presentation. 12 Thank you for coming before us today. 13 It is now 20 to 1:00 and I know we are really 14 behind and we have the Federation of Ontario Cottagers 15 Association. 16 The question then becomes: Do we go straight 17 ahead now or do we break now and start later? 18 Would you like to talk with -- is it Mr. McGee 19 who is representing them? 20 --- Pause 21 THE PRESIDING MEMBER: Ms Kwik, you can go and 22 talk with Mr. McGee. 23 MS KWIK: Mr. McGee, would there be a problem 24 with your panel going on after lunch? Is that a 25 possibility? 26 --- Pause 27 THE COURT REPORTER: I'm sorry, sir. Could 28 you come to the microphone, please? || Vol. Pg.794  1 MS KWIK: Could you come to a microphone, 2 please, gentlemen? 3 THE PRESIDING MEMBER: Judy, you can go and 4 talk to him. 5 --- Pause 6 MR. McGEE: We do have a preference to 7 proceed now. 8 I think probably we will not likely be the 9 full hour by any means, depending on questions, because 10 I do have a medical condition that is worsening rapidly. 11 THE PRESIDING MEMBER: We will go ahead then. 12 Mr. McGee, please. 13 --- Pause 14 THE PRESIDING MEMBER: I'm not sure who is 15 chairing the presentation, but please proceed and 16 introduce everyone. 17 PRESENTATION 18 MR. WRIGHT: All right. 19 Good afternoon. My name is Robert Wright. I 20 am counsel to FOCA. On my right-hand side is the 21 Executive Director, Wendy Moore; and on my left-hand 22 side is Mr. John McGee. 23 THE PRESIDING MEMBER: I recognized Mr. McGee, 24 that's why I approached him. Thank you. 25 Please carry on. 26 MR. WRIGHT: Not at all. 27 Thank you for your indulgence. We will try to 28 bear in mind the time and move along quickly. || Vol. Pg.795  FOCA, Presentation 1 We have presented you already with an outline 2 of the submissions. 3 In the presentation we will first of all be 4 introducing FOCA. I will ask Ms Moore to briefly do 5 that. 6 We will then just point out the issues we have 7 raised in our written submissions but will not be going 8 to any depth in those. 9 We have put in a section indicating the 10 support we have for submissions covered by other 11 intervenors. However, for today we will be selecting 12 two areas to make submissions on, not for any reason 13 because the other areas of submission are any less 14 important but because we feel they have been covered 15 largely by other presenters and well done in that 16 regard. 17 So we will be focusing on environmental, 18 health and safety concerns and the rate design. 19 Without further explanation I intend to ask 20 Ms Moore to briefly introduce who FOCA is. FOCA has not 21 presented before you before and we thought it would be 22 some help for you to know who is at the table. 23 MS MOORE: Good afternoon. 24 FOCA is the voice of Ontario's cottagers, 25 about half a million of them. 26 We are here today to represent the 500 local 27 and regional cottagers associations that belong to our 28 umbrella organization. Together we represent about || Vol. Pg.796  FOCA, Presentation 1 83,000 individual property owners and approximately half 2 a million cottage users. Our membership covers most of 3 the province. 4 We are a large not for profit corporation with 5 a broad two-part mandate. The first half of our 6 mission -- and I quote -- is: 7 "...to provide representation, assistance 8 and leadership to and for cottagers' 9 associations on issues affecting their 10 interests." (As read) 11 In the past year FOCA has responded to more 12 than 175 issues on behalf of its membership. Our office 13 receives somewhere in the neighbourhood of 10,000 14 inquiries annually. 15 This year the majority has concerned property 16 taxes and municipal services (or the lack thereof); the 17 impacts of downloading; land use planning and 18 development concerns; hydro and energy issues; anything 19 to do with roads, from liability, maintenance standards 20 and fuel taxes to dust suppressants and municipal 21 assumption (or the lack thereof); changes to boating 22 regulations; Cottage Watch, which is our crime fighting 23 program; emergency response services; water levels; 24 water quality; and a wide range of environmental issues. 25 Most of our inquiries are referred to our 26 committees, advisory groups, and extensive network of 27 volunteer experts for response. 28 As well, we maintain partnerships with related || Vol. Pg.797  FOCA, Presentation 1 organizations, like the Ontario Provincial Police, the 2 Ministry of Environment and the Ontario Federation of 3 Naturalists. 4 The secret of our success is the commitment of 5 our volunteers. We have about 200 of them. Each year 6 they donate about 13,000 hours of their time to FOCA. 7 Their activities and achievements are profiled 8 in "FOCA News", which is published six times a year, and 9 "Cottage Life Magazine", which you may be familiar with. 10 The second part of our mission is to encourage 11 good environmental stewardship on the part of every 12 cottager. 13 We are best known for our ongoing work in lake 14 stewardship. We recently published "Take the Plunge: 15 Stewardship of Ontario's Waters", which is a 24-chapter 16 how-to manual. It was launched at the North American 17 Lake Management Society symposium, and it created quite 18 an international splash and established FOCA firmly as a 19 leader in this field. 20 We run an extensive lake stewardship network 21 which offers a variety of hands on water testing 22 opportunities, as well as several other programs that 23 promote our primary goal of pristine water quality. 24 On the environmental front, we were also 25 heavily involved in the Lands for Life process that 26 determined the future of Ontario's crown lands. Our 27 environment chair represented our interests at the Great 28 Lakes-St. Lawrence round table. || Vol. Pg.798  FOCA, Presentation 1 If you measure FOCA's relevancy to its members 2 in terms of influence, volunteer commitment, 3 participation in programs or the number of clients 4 served, we are very successful organization. 5 I heard it said that the most successful 6 people in the business world are problem solvers, and I 7 think that is a good description of what FOCA does. And 8 we do it mostly with volunteers. 9 Thank you. 10 MR. WRIGHT: Thank you, Ms Moore. 11 The issues that we raised in the written 12 submissions that were largely prepared by Mr. McGee -- 13 he is an electrical engineer with 36 years of experience 14 in various areas of the industry -- included 15 environment, rate design, contributed capital and the 16 allowable rate of return. 17 We have listened to a number of the other 18 presentations and certainly read all of them, and 19 Mr. McGee has been involved from early on in the 20 process. The ones we thought we would highlight are the 21 submissions where we felt there was particular support 22 or we had particular support for their position. 23 One was the presentation by Pollution Probe. 24 They talked about energy efficiency and rate design and 25 suggested eliminating anti-efficiency incentives and the 26 use of regulatory mechanisms to create pro-efficiency 27 incentives. 28 The second group we thought we would highlight || Vol. Pg.799  FOCA, Presentation 1 was the Green Energy Coalition. Again, they dealt with 2 cost effective energy efficiency and incentives for 3 conservation programs. They suggested shared savings 4 mechanisms, lost revenue adjustment mechanisms and DSM 5 variation accounts. 6 The next group was the Consumers Association 7 of Canada. They focused on the rate impact on small 8 consumers and suggested a lower rate of return for 9 publicly owned utilities. We thought, until their 10 presentation, the rate impact perhaps had been somewhat 11 neglected. 12 The Municipal Electric Association, which I 13 believe is still to make its presentation later on 14 today, again deals with rates and rate impacts on 15 customers. They suggest possible inequities and a 16 revised methodology for establishing initial rates. 17 So we will be interested to hear their 18 presentation later in the day. 19 There was a report filed by Energy Cost 20 Management Inc., which was a rate impact study showing 21 enormous increases. We will briefly refer to those in 22 our submissions. 23 And finally an unlikely bedfellow, the Power 24 Workers' Union suggested that the groundwork for future 25 implementation of a fully integrated scheme of 26 reliability and customer satisfaction measures were 27 appropriate. 28 These are quality of service issues, which is || Vol. Pg.800  FOCA, Presentation 1 something that we will be dealing with and honing in on. 2 Moving to our specific issues, we thought we 3 would cover -- and I was very interested in the previous 4 presentation that dealt with philosophical issues on a 5 macro scale. I suppose ours are philosophical issues on 6 a micro scale, using the framework of the Handbook as 7 presented. 8 But even if you accept Mr. Roman's submissions 9 and either throw the Handbook out or start over with 10 something else, it is our view that the points we are 11 going to make should be incorporated and must be 12 incorporated, given the objectives of the two acts, into 13 any new scheme that is presented or developed. 14 On the environmental health and safety issues, 15 we first looked to the objectives and purposes of the 16 act which have been referred to, I suppose, somewhat ad 17 nauseam for you, but each time we present they are new 18 for us. 19 I tried to highlight some of the ones I 20 thought were particularly relevant to our issues. There 21 are common objectives and purposes in both acts, as you 22 know, and the ones most relevant for us are, first of 23 all: 24 "To protect the interests of consumers 25 with respect to prices and the 26 reliability and quality of electricity 27 service." 28 The second is: || Vol. Pg.801  FOCA, Presentation 1 "To facilitate energy efficiency and the 2 use of cleaner, more environmentally 3 benign energy sources in a manner 4 consistent with the policies of the 5 Government of Ontario." 6 We looked also at the draft guidelines or 7 filing guidelines that have been put out for mergers and 8 acquisitions with interest, because it covered two areas 9 and I think anticipated a concern that we are raising 10 now that there are certain things or a gap in the 11 Handbook, if you will. 12 Under the heading of Financial Viability in 13 those draft guidelines for mergers, et cetera, there is 14 a requirement that the utilities: 15 "Provide a public safety and 16 environmental audit of the facilities of 17 the parties to the proposed transaction, 18 if one has been prepared." 19 And it goes on with some other suggestions if 20 one has not. 21 That is in Section 2.5.4 of those Draft 22 Guidelines. 23 Secondly, the draft guidelines, under the 24 heading Facilitate Energy Efficiency and Use of 25 Environmentally Benign Energy Sources -- clearly words 26 taken from the objectives of the two acts -- it suggests 27 that a utility must: 28 "Provide details on the environmental || Vol. Pg.802  FOCA, Presentation 1 policies established by each of the 2 parties to the proposed transaction and 3 changes to these policies, if any, that 4 would arise from the transaction." 5 So those are two indications that the Board 6 has pre-empted what we are saying, but I think they show 7 a concern. We support those initiatives and we will ask 8 that they be taken further and incorporated, not 9 specifically these ones but the theory and the policy 10 incorporating the objectives of the act, that those be 11 incorporated into the PBR Handbooks as well. 12 We have quoted from the Ontario Energy Board 13 annual reports for 1997 and 1998. In that, Mr. Laughren 14 makes some interesting expressions of the foundations 15 for consumer confidence in the changing role of the 16 Board. 17 The words he uses are interesting because they 18 aren't taken directly from the objects of the act, but 19 we think they apply by inference. 20 "What will not change is the Board's 21 traditional role of protecting the 22 consumer and preserving the safe and 23 reliable supply and delivery of energy. 24 The Ontario public can rest assured that 25 consumer protection and system integrity 26 will remain unswerving commitments of the 27 Ontario Energy Board." 28 And he goes on to say: || Vol. Pg.803  FOCA, Presentation 1 "Consumer protection is the heart of the 2 expanded role envisaged for the OEB in 3 the provincial government's White Paper 4 on electricity." 5 We believe there's a gap in the Draft 6 Handbook. Chapter 5 deals with service quality. We 7 feel that the objectives and purposes, two of which I 8 quoted earlier, direct that environment, health and 9 safety concerns be essential components of service 10 quality and must be incorporated into the Handbook. 11 Now, again, the Green Energy Coalition and 12 Pollution Probe have dealt with energy efficiency and 13 conservation efforts and clean energy programs, so we 14 will not again thrash through their suggestions. We do 15 support them. However, in our view protection of the 16 environment is not only a threat, it is one of the 17 objectives and purposes of the Act. It's referred to in 18 the preamble. It's right on the cover of bill 35 to 19 protect the environment, yet in our view the PBR Draft 20 Handbook omits that objective. 21 More specifically, we refer to chapters 5 and 22 section 6.4(3). Now, in chapter 5 of the Handbook, 23 there's a table, table 5-1. It has customer service 24 indicators and service quality indicators. 25 When I went to school, there was a saying that 26 gum chewing would be conspicuous by its absence. Well, 27 I would suggest that environmental issues and concerns 28 are conspicuous by their absence in these indicators. || Vol. Pg.804  FOCA, Presentation 1 The recommendations that we will be making will be 2 largely with regard to those tables and their inclusion 3 of environmental indicators as well. 4 We thought we would briefly mention some areas 5 in the management by the distribution utilities where 6 they are likely to run across environmental concerns. 7 The first one that we refer to was PCBs which are a 8 known environmental hazard. 9 They will have to manage PCBs. They may have 10 to remove them, destroy them, but in any event, they 11 will have to be dealt with just as part of their ongoing 12 business. 13 In addition, there are issues regarding the 14 pole treatment methods used and the substances used to 15 preserve them. There are also issues regarding 16 herbicides for the running of lines. 17 Those are the kinds of things that they will 18 run across when they are managing their activities. 19 There is nothing under the service quality indicators to 20 deal with those kinds of concerns. We are not 21 suggesting we should necessarily be telling them how to 22 do things, but this is a reporting requirement. If 23 things aren't reported, it will be very difficult to 24 deal with the issues and to base any decisions being 25 made on actual fact. 26 Another matter, in fact Mr. McGee was involved 27 in this at the time, and that's education of the 28 community regarding the electrical safety programs. We || Vol. Pg.805  FOCA, Presentation 1 have a question as to whether those kinds of programs 2 would be viable when the change in economic philosophy 3 is moving towards profit. 4 Now, we also make reference to the OHSC 5 distribution rate order application made on December 7, 6 1998. If one takes a look at that, we can lift a number 7 of pages where they make reference to environmental 8 protection and employee and public health and safety 9 measures. 10 I don't intend to run through them, but those 11 can be found at pages 29, 52, 53, 58, 62, 90, 97, 98, 12 100, 104 to 107 and 114 to 115. I believe we have that 13 with us here. Of course, you do as well, but we do have 14 a copy here for reference. In any event, in our view, 15 that is one example of the kind of thing the 16 distribution utilities can look at. In fact, there's a 17 number of examples there. 18 In short, it is our submission on this issue 19 that the Acts do not simply direct a change in economic 20 philosophy. Their stated purposes do not stand in 21 isolation. Consumer protection and protection of the 22 environment are not mutually exclusive objectives. This 23 is not, we suggest, reflected in the Draft Handbook. 24 We, therefore, recommend, and we make three 25 recommendations on page 4 of the outline, we recommend 26 that the costs and results of energy efficiency programs 27 and the plans for the following year of electric 28 distribution utilities be reported to the OEB annually. || Vol. Pg.806  FOCA, Presentation 1 We further recommend that there should be 2 mandatory public safety and environmental audit 3 requirements. At the very least, the utilities should 4 report their environmental, public health and safety 5 policies, records and accomplishments. 6 A fourth matter that we have not specifically 7 addressed in the outline, but there is reference in the 8 service quality chapter to -- I believe it's remedial 9 steps. It's not intended for there to be remedial 10 activities. That was in paragraph 5.4. That book 11 suggests that distributors whose performance fall below 12 the minimum service quality standards for indicators for 13 which monitoring and reporting is required must include 14 a remedial action plan with their annual reports. 15 I think the idea was that by second generation 16 there would be enough data to have economic consequences 17 to govern these activities. 18 In short, our first suggestion is we want to 19 add these things to the list of service quality. We 20 don't want to see them under the heading "Indicators not 21 requiring reporting". That's on table 5-1. We would 22 like to see these indicators reported and we would like 23 to see some form of remedial activity to deal with the 24 situation should those indicators consistently fall 25 below what can reasonably be considered quality 26 standards. 27 The second point we wish to deal with today 28 was rate design. Again we turn to the objectives and || Vol. Pg.807  FOCA, Presentation 1 purposes of the Act. I won't go over the previous ones. 2 I have referred to the bill 35 preamble which says: 3 "An Act to create jobs and protect 4 consumers by promoting low-cost energy 5 through competition, to protect the 6 environment, to provide for pensions and 7 to make related amendments to certain 8 Acts." 9 We also refer to section 78(3) which is the 10 just and reasonable rates section. 11 By way of general comments, other intervenors 12 have noted that the move to market based rates of return 13 will raise the total revenue requirements of MEUs by 14 about 50 per cent. By our calculation, this alone will 15 work through to approximately a 7.5 per cent increase in 16 the average customer's bill. In the Draft Handbook they 17 recognize that the potential rate impacts may be 18 substantial. 19 I referenced earlier the ECMI document which 20 was tabled with you yesterday. I understand it pointed 21 out that the rate impacts in the residential class were 22 as high as an increase of 327 per cent for small 23 customers. In the general service class, the rate 24 impact was calculated to be an increase or could be an 25 increase of over 700 per cent. 26 Those are huge, huge increases. I know that 27 information, I would suggest, is coming to us fairly 28 late in the day, but certainly in time to consider. || Vol. Pg.808  FOCA, Presentation 1 Now, our main point to be made is the 2 consequences of the split between fixed and variable 3 consumption components. By "variable" we are also 4 saying consumption. 5 It is our belief that most of the impact of 6 those percentage increases are due to the proposed split 7 between the fixed monthly and variable consumption 8 components of the distribution charges. That comes out 9 of Appendix A, which is Table 2-10 in the Draft 10 Handbook. That is at page 11. 11 If you look at the figures under the column 12 "Distribution Revenue" and then "Variable Revenue" and 13 "Service Charge Revenue", I believe the percentages 14 really come down to approximately 72 per cent and 28 per 15 cent, but we rounded those off to 70/30. 16 Now except of a handful of MEUs, virtually all 17 the distribution revenue is presently collected in a 18 variable consumption charge. When you stretch from the 19 current rate structure to a structure that will 20 overemphasize fixed charges, we believe that will have a 21 severe impact on the bill to small consumers. 22 And then we would like to suggest an analogy 23 to you, that if you are using the method used by the 24 Draft Handbook, if you were to go and purchase $20.00 of 25 gasoline for your vehicle, you would be paying 26 approximately $14.00 or 70 per cent for the privilege of 27 having the gas pump turned on, and then $6.00 or 28 approximately 30 per cent being 20 cents per litre for || Vol. Pg.809  FOCA, Presentation 1 30 litres of gasoline. 2 Now what that means is that because of the 3 pricing it would be an encouragement for wasteful 4 gasoline consumption and smart people would get cars 5 with very large gas tanks. A motor home and a moped 6 would fill up and be paying the same fixed charge. It 7 just doesn't make sense, and we believe that analogy 8 falls through with the current proposed fixed and 9 variable split. 10 That kind of split will also, as pointed out, 11 I think, by the earlier presenters, Pollution Probe, et 12 cetera, will undermine consumer-initiated electricity 13 and energy conservation efforts, result in more 14 consumption with the consequent results in pollution and 15 the connected health effects. I think they referred to 16 the OMA submission on the effects of air pollution on 17 the health of individuals. 18 So our recommendation on this issue is that 19 the monthly charge should be determined on the basis of 20 rational customer-specific charges such as meter 21 reading, billing and collection and that all other costs 22 should be recovered in the variable or consumption 23 component. 24 In addition, the .62 cent per kilowatt hour 25 variable charge is too low and much less than the number 26 currently being used by utilities in Ontario. 27 Thank you. Those are the submissions that we 28 wish to make and Mr. McGee is available as well on any || Vol. Pg.810  FOCA, Presentation 1 particular technical questions. So if you have any 2 questions we would be pleased to deal with them. 3 Thank you. 4 THE PRESIDING MEMBER: I have a quick question 5 if I might ask before we ask other questions and that 6 is, I was looking at the analogy with the gasoline 7 purchase and the analogy with the distribution rate as 8 shown in Appendix A, page number 210 and it crossed my 9 mind that the gasoline purchase analogy doesn't actually 10 compare with the Appendix A, page 210 because 11 Appendix A, page 210 -- Table 210, as I understand it, 12 has removed the cost of electricity. 13 I believe -- and Miss Kwik can correct me on 14 that -- but I think that deals with other news related 15 to the delivery of the electricity having removed the 16 cost in part. Is that correct? 17 MS KWIK: That is correct, Mr. Chair. 18 THE PRESIDING MEMBER: That is just an 19 observation that I wanted to ensure. 20 MR. McGEE: We know that all analogies are 21 imperfect and we did recognize that that when you buy 22 gasoline it includes a lot more than just the cost of 23 operating the gas station, but the principle is there 24 that when you go into a gas station you don't pay a 25 fixed charge to the owner of that gas station for the 26 privilege of using his pump. That is truly and 27 absolutely a competitive market. These are monopolies 28 we deal with. It is only monopolies that can get away || Vol. Pg.811  FOCA 1 with charging a fixed monthly charge. 2 In fact, a monopoly that had complete power 3 would collect all of its costs up front and a capital 4 contribution from a customer and never have to issue a 5 bill to them again. So it is an illustrative analogy. 6 We are quite aware that the gasoline analogy contains 7 things that just other the cost of distribution. 8 THE PRESIDING MEMBER: Thank you. 9 Miss Kwik, do you have something to add? 10 MS KWIK: Yes, I do, Mr. Chair. Thank you. 11 With regard to service quality you are 12 suggesting that items such as management of PCB and 13 standards for usage of herbicides should be included. 14 Is that correct? 15 MR. McGEE: Yes, that's right, yes. 16 MS KWIK: Now, I just wanted to understand. 17 Are there currently management procedures as well as 18 standards for herbicides that are put forth by the 19 Ministry of Environment or Health that utilities have to 20 abide by? 21 MR. McGEE: The Ministry of the Environment 22 does have a say on both of these things, but I think in 23 the way it finally shakes out is that the compliance 24 with it is essentially voluntary and the utility itself 25 has to make these judgements and making these judgements 26 without having to report them, we don't think is really 27 appropriate. 28 MS KWIK: So is it the suggestion here then || Vol. Pg.812  FOCA 1 that the Board adopt the Ministry standards and 2 management procedures and have utilities report on 3 those? 4 MR. McGEE: I am not suggesting that the OEB 5 take over the responsibilities of the Ministry of the 6 Environment, but where there is an area in which the 7 Ministry of Environment des not have adequate regulation 8 then I think that the OEB has a responsibility as the 9 prime regulator of these distribution utilities to fill 10 those gaps. 11 MS KWIK: I am just having trouble sort of 12 with the details of such a plan. What would the 13 utilities have to report to the Board? 14 MR. McGEE: We have mentioned the example of 15 the Ontario Hydro Services Company. They submitted a 16 very detailed distribution rate order application last 17 December which I went through in detail and picked out 18 from there all of the environmental initiatives they 19 have that are not mandated by government. And we think 20 that all utilities should bring those forward to the 21 Board and tell the Board what they are. 22 MS KWIK: So those would in fact be programs 23 then that the utilities -- 24 MR. McGEE: Programs. And they are certainly 25 cost-eligible. The cost of them could certainly be 26 passed onto the consumer. They are types of programs 27 that people don't think of too much, that customers 28 really, really need and when they are not mandated by || Vol. Pg.813  FOCA 1 some other branch of the government, I think the OEB 2 does have a responsibility to at least require the 3 reporting of these programs. 4 MS KWIK: Thank you for the explanation. 5 MR. McGEE: Well, the reporting of these 6 programs to the Ontario Energy Board while we are in a 7 position -- nor the government agency that has clear 8 jurisdiction, I think, that there is a responsibility on 9 the Board to look at these things. The public safety is 10 another example that we use, education to children and 11 that is not mandated by everyone. It is something that 12 a lot of the utilities do as a matter of course right 13 now, but then once being profit-driven that is probably 14 a program that would be dropped. 15 MS KWIK: Thank you, Mr. McGee. The Court 16 reporter was just trying to get you to repeat because he 17 was not able to hear your answer. 18 MR. McGEE: Oh, okay. Then I added much more 19 than -- 20 THE PRESIDING MEMBER: I think it is a caution 21 to all of us to try and speak into the microphone 22 because otherwise the microphone doesn't pick it up and 23 the recording is important because that is where they 24 get the transcripts from. In fact, I know that I am 25 being looked at periodically for not speaking close 26 enough to the microphone. 27 MR. WRIGHT: If I could perhaps just add 28 something. You talked about reporting to the Ministry || Vol. Pg.814  FOCA 1 and reporting here. 2 We think there is a real value to have those 3 matters added to the reporting requirement. It will add 4 to transparency. 5 It may not be the same information one gets at 6 the ministry in the same form. It may be industry-wide. 7 There are other issues in obtaining that information 8 from the ministry and so it would be more accessible, we 9 think. We think it is a service quality issue. 10 MS KWIK: Thank you. 11 MR. McGEE: Just to add a little bit, the 12 utilities are going to be regulated by the OEB. They 13 are going to feel a prime responsibility to meet what 14 you ask them to do, more so than all these other 15 peripheral agencies. 16 THE PRESIDING MEMBER: Mr. Vlahos. 17 MEMBER VLAHOS: Thank you, Mr. Chairman. 18 Mr. McGee, I have no questions really, just 19 some comments as to what I have heard from you this 20 morning. 21 It seems to me that the overall impression of 22 the Board is that it will do everything. It will be a 23 super Board that will regulate the industry from rates 24 down to, I don't know, we mentioned environmental issues 25 which may belong somewhere else. I get that impression 26 also from some other commentators that have come before 27 the Board this week. 28 I guess I am somewhat concerned that if that || Vol. Pg.815  FOCA 1 is the impression that is left with not just the 2 organization but beyond the organization that maybe we 3 have not done a good job in terms of delineating the 4 roles of this Board versus other agencies or government 5 departments. That is the sense that I get when I go 6 through your submission. 7 I get the impression that -- you are talking 8 about electrical safety education program for example, 9 it is just not my understanding that we are going to get 10 into all those things. We are an economic regulator 11 primarily. 12 Yes, there are some reliability issues, safety 13 concern issues, service issues, more importantly, that 14 we would like some reporting to ensure that service 15 quality doesn't deteriorate because of the incentives 16 that are being created to reduce costs in a PBR regime. 17 But with that preamble, do you have 18 anything -- 19 MR. McGEE: I think the wording of our 20 regulations or our recommendations were pretty specific. 21 We did not -- we were not trying to say that you should 22 now become the regulator of PCBs or all these other 23 things, but we were suggesting that the utilities should 24 report these things to you, that if one utility reports 25 a great big program and the other utility reports zero 26 there is going to be a little bit of subtle pressure put 27 on the utility that poses zero. 28 It's the same thing on the energy efficiency || Vol. Pg.816  FOCA 1 programs. I don't think anyone has suggested that the 2 OEB make energy efficiency programs mandatory, but the 3 mere fact of asking them to report what they are doing 4 sends a very clear signal that, yes, there is something 5 in our Act that deals with that. 6 So just in summary, we don't think you have to 7 become regulators of environment and all the rest, but 8 you are the clearing house for the information, they are 9 going to have to make all of their submissions to you 10 and they should be telling what they are doing in these 11 regards. That is really all we are asking for. 12 MEMBER VLAHOS: Do you see the role of the 13 Board also, once it receives that information, to the 14 extent there is no ratemaking implications, would the 15 Board be simply an agent for reporting those to the 16 appropriate body? Is that how you see it? 17 MR. McGEE: I think you could probably publish 18 it and send it back out to the utilities. 19 For instance, you are going to be asking them 20 to measure things like how long it takes to answer a 21 telephone, which we think is far down the list of 22 priorities from an environmental concern. We all know 23 when there is a power outage of course that you may 24 never get through on the telephone and the utility would 25 never know that. 26 So some of the indicators that you do have I 27 think are of much less importance than the ones that we 28 had raised here. || Vol. Pg.817  FOCA 1 MEMBER VLAHOS: Mr. Wright, did you want to 2 add something? 3 MR. WRIGHT: You are very observant. 4 MEMBER VLAHOS: I have been sitting here for 5 some time, so -- 6 MR. WRIGHT: Thank you for asking. 7 I think you do have -- one of the points I 8 think I tried to make was that we are not just concerned 9 with price and I think the objects -- I'm looking now at 10 the Ontario Energy Board Act, at its objectives, and I 11 think you can read those objectives listed in section 1 12 numbers (1) to (6), you could read them all 13 independently, even independently, in (3) where it talks 14 of protecting the interests of consumers with respect to 15 prices and the reliability and quality of electrical 16 services. 17 My submission would be that quality does bring 18 in these factors. 19 We are not asking you to sit as the 20 environmental board, but there are reporting 21 requirements here and we think that you would have 22 jurisdiction under either 1.3 on the quality of the 23 electricity service or reading into that section as a 24 whole sub (6) of that section, which I won't go over 25 again but it deals with environment. 26 I think you could proceed on the basis, as the 27 Handbook has, that we are looking at solely economic 28 factors, but I think that is wrong. I think that is a || Vol. Pg.818  FOCA 1 mistake and I don't think it is one of the objectives as 2 laid out in the Act. 3 I think one has to be careful how far one 4 goes, but I don't think it would be going too far to 5 include in service quality issues of environmental 6 monitoring. In your own directives on the mergers you 7 have identified a concern in that regard, albeit some of 8 it is financial, it is financially related on the audit 9 requirement, and perhaps the request for an audit is one 10 extreme. 11 But reporting requirements of other matters 12 that we have raised I think you are entitled to ask for, 13 to include in the service quality. We have put it in 14 service quality. We could have put another chapter in 15 to deal with 1.6 of the Act, we just happen to be 16 dealing with it within the framework of the proposed 17 Handbook and we thought that is maybe where it is 18 slotted in. But I think it can come within there and 19 should. 20 MEMBER VLAHOS: Okay. 21 My other observation within the same topic is 22 that my sense was, and perhaps I'm wrong, that FOCA 23 viewed this PBR Handbook as the all-inclusive document 24 that would govern the regulation of electric utilities 25 henceforth and it will not be. I mean, there will be 26 other documents that will govern certain other 27 activities, be it environment, be it amalgamations. 28 Were you aware of this, that this is not the || Vol. Pg.819  FOCA 1 end product in terms of the Board's role in terms of 2 electricity regulation? There may be guidelines as to 3 capital expansion and what you have to worry about in 4 terms of the environment? 5 MR. WRIGHT: I take it you are not talking 6 about the rate submissions. The rate submissions on the 7 split of the rates I think tie in directly with the work 8 of the PBR Handbook. 9 I take it your question was directed more to 10 the environmental issues? 11 MEMBER VLAHOS: Yes. Stemming from the 12 environmental issues which you have brought up, yes, 13 that the Board has several instruments in regulating an 14 industry such as the gas industry and there are 15 guidelines to deal with how you file for rates and what 16 the Board looks at in approving rates, there are 17 guidelines as to how do you construct a pipeline, okay, 18 the kinds of tests that you have to meet, codes, 19 et cetera. 20 So there are various instruments and I just 21 want to point out that the PBR Handbook deals mainly 22 primarily with the rate setting of the industry. There 23 will be additional documents that deal with a number of 24 other things. 25 Capital expenditures may also include 26 environmental concerns. I just want to understand 27 whether FOCA was aware of that. 28 MR. WRIGHT: Yes. I can tell you that I spent || Vol. Pg.820  FOCA 1 a phenomenal amount of my own time reviewing all of the 2 various documents that have both been put out for 3 comment, and we know there are others coming down the 4 road too. 5 We did not comment on the capital contribution 6 today, because we know it is going to be addressed -- or 7 we hope it is going to be addressed in the system 8 expansion document that is being worked on. We are 9 quite aware of all of the documents that the OEB is 10 producing, but we feel that this one is -- this is where 11 the rubber hits the road. This is where it impacts 12 directly on consumers. It is the central document, in 13 our opinion, of the whole distribution industry. All 14 the others are just bells and whistles added on to this. 15 MEMBER VLAHOS: Thank you. Just one last 16 question. 17 You gave the example of the gasoline purchase, 18 and of course we have some utilities that actually like 19 the idea of recovering all the fixed costs from a fixed 20 charge. There is subsequently no risk left to the 21 shareholder. 22 Let me put this to you: If indeed the price 23 of gas per litre was 20 cents and the cost of turning on 24 the pump was $6.00, would you have a problem with that 25 in pricing in a way that prices follow a course? If 26 indeed the fixed charge recovers the fixed cost to a 27 system from a cost causation point of view, what is the 28 problem? || Vol. Pg.821  FOCA 1 I understand the environmental part of it, but 2 from an economic efficiency point of view do you see a 3 problem? 4 MR. McGEE: The problem is that if you hired 5 ten economists and lawyers to look at the electric 6 utility and said what are the fixed costs and what are 7 the variable costs, no two would come back with the same 8 answer. 9 A utility manager himself would want to say 10 it's all fixed costs. I would like to recover it in all 11 fixed costs for that therefore insulates me from all 12 competition. I don't have to worry about any volume 13 fluctuations or anything else. 14 A consumer would want to see it all in the 15 consumption charge. There is a balance in there 16 between. 17 We are suggesting here that you fixed the 18 wrong component. You fixed the variable component on 19 assumptions that we don't think are valid. We think you 20 would be more advised to look at the fixed component and 21 see clearly what everyone can agree should go into that 22 fixed component. 23 We have also heard, again from the electric 24 utility side, that they would like to include in the 25 fixed component the cost of what they call a minimal 26 distribution system, without ever defining what that 27 means. 28 Your own task force that dealt with this issue || Vol. Pg.822  FOCA 1 came up with what I thought was a very excellent 2 suggestion. They said the fixed charge should consist 3 of all the costs from the common distribution system 4 down to the customer premises, including the wire that 5 goes to the customer's premises, meter reading, billing 6 collection, and on and on. 7 That was a very logical approach. However, it 8 was overturned in the final Handbook. 9 That is something, by the way, that could be 10 explained to any consumer that phoned up and asked. 11 The other problem that you have with this 12 fixed/variable split, this 50 per cent increase in the 13 distribution revenue requirement coming from the move to 14 market-based rate of return all ends up in the fixed 15 monthly charge. None of it goes into the variable 16 charge. And that is absolutely inappropriate. 17 You can't ask the moped to pay the same profit 18 contribution to Imperial Oil as the motorhome or 19 whatever. There are serious problems in that Appendix 20 A. 21 A much better approach is -- does that answer 22 your question? 23 MEMBER VLAHOS: Yes, it does. Thank you for 24 that. 25 Thank you, Mr. Chairman. 26 THE PRESIDING MEMBER: Thank you, Mr. Vlahos. 27 Dr. Zerker...? 28 MEMBER ZERKER: Ms Moore, I just want to tell || Vol. Pg.823  FOCA 1 you that I appreciate the work you do with the 2 organization, as a cottage owner -- although one that 3 does not use electricity. 4 That leads me to a couple of comments. 5 I do understand your point that as an economic 6 regulator we are regulating a service, and when the 7 quality of the service changes then the commodity is 8 changing. That is an economic reality. I accept that. 9 I don't know if we can identify as easily the 10 environmental input directly into rates as we can 11 service. Service, I can see, has a direct connection to 12 our economic regulatory function. 13 I just want to make that comment. 14 I would like to ask you -- and this is an 15 informational thing. You say that virtually all MEU 16 distribution revenue is presently collected in a 17 variable consumption charge. 18 I am a little bit confused, and maybe you can 19 help me. As I mentioned to you, my cottage is not 20 serviced with electricity from the system. I started 21 making some inquiries from Ontario Hydro, from the 22 Bancroft service area, and they informed me that the 23 rate would be fixed at $27.85 -- I may be off a few 24 cents; 84 cents, or something like that -- per month, 25 regardless of whether I bought one single kilowatt of 26 energy and whether or not I shut it down in the 27 wintertime. 28 Is that not a fixed charge? || Vol. Pg.824  FOCA 1 MR. McGEE: We did not come at this from the 2 perspective of FOCA as individual members. We are 3 looking at the whole province, and we were looking at 4 MEUs particularly. I believe there were only two, maybe 5 three or four, MEUs that have a fixed monthly charge. 6 Virtually all of the rest have a 250-kilowatt hour block 7 with a certain rate, and the balance block is at a 8 different rate. 9 Ontario Hydro Services Company introduced that 10 monthly service charge, and I am sending up a big 11 warning flag for the Board here that when they did it, 12 it caused massive chaos and we are still feeling the 13 toothaches today. 14 As the manager of the hydro portfolio, it is 15 the number one concern that cottagers have. They see it 16 as $27.80 for nothing. 17 MEMBER ZERKER: They do. Ontario Hydro, then, 18 does have a fixed charge. 19 MR. McGEE: Ontario Hydro has it, Toronto 20 Hydro has it, Milton Hydro, I believe. I shouldn't be 21 quoting individual utilities. 22 MEMBER ZERKER: I was confused. 23 MR. McGEE: It is only a small component of 24 the total distribution utilities in the province that do 25 that. All of the others bill on a basis of so many 26 cents a kilowatt hour for the first 250-kilowatt hour 27 block, and the rest -- Judy may know more accurately 28 than I do how many there are, but it is only a handful. || Vol. Pg.825  FOCA 1 I think it is probably less than five. 2 MEMBER ZERKER: Then my question to you, 3 Mr. McGee and Ms Moore, is: Doesn't that large utility, 4 Ontario Hydro, affect your cottagers more directly than 5 say a small utility, one of the smaller utilities? 6 How does it balance out between your MEUs that 7 do not have a fixed charge and Ontario Hydro that does 8 vis-a-vis cottagers? 9 MR. McGEE: Well, I can tell you that we have 10 members that live in New York State, who live in 11 year-round houses in New York State, and they can't 12 understand why they were paying three times as much per 13 kilowatt hour of electricity in Ontario than they were 14 paying in New York State, which is the highest 15 jurisdiction in the world practically -- or in North 16 America, certainly. 17 We recognize that we are in a basket. We have 18 a special customer classification for summer cottages. 19 So any changes made in the rate structure for us is 20 simply going to move money from one customer as another. 21 FOCA as an organization represents them all, so we are 22 not advocating that. 23 We are just putting up a big red warning flag, 24 that when you do this for the rest of the province there 25 is going to be big time trouble, as you can see for the 26 numbers that ECMI produced. 27 I don't think that the Board would be able to 28 justify the components that are going into that fixed || Vol. Pg.826  FOCA 1 monthly charge. You are fixing the variable component, 2 and the monthly charge becomes the catch-all for 3 everything else. No one could ever explain that on the 4 telephone to an irate consumer. 5 I have to deal with lots of them in my 6 capacity as advisor to FOCA. You must be able to have a 7 fixed charge that you can clearly explain to customers 8 as to what it consists of, and the rest you collect in a 9 consumption component. 10 MEMBER ZERKER: From your experience, did 11 Ontario Hydro, the other municipalities that did 12 establish that fixed charge, did they provide a cost of 13 service rationale for it? 14 MR. McGEE: Well, they never did to us. Of 15 course, they were unregulated. We were always told 16 after the fact. Ontario Hydro, even though it regulated 17 municipal utilities, when it came to their own rates, no 18 one was given the slightest hint as to what they were 19 going to do until it had in fact already had been 20 approved by their Board and then we were told. That was 21 the way they self-regulated. 22 MEMBER ZERKER: That was not a period when the 23 Board was approving rates. 24 MR. McGEE: I think the Board only looked at 25 the wholesale rates. It never looked at retail rates. 26 Even at the wholesale level, you didn't have the 27 authority just to review them. 28 MEMBER ZERKER: Right. || Vol. Pg.827  1 MR. McGEE: Then they went ahead and did their 2 own thing. With rural retail customers, it was even 3 more arcane, I think, because they made their decisions, 4 put them to their own Board of Directors for approval. 5 They were approved and then we were told. 6 MEMBER ZERKER: That's the process, not the 7 Board's. 8 MR. McGEE: We do very much appreciate the 9 open type process that the Board has, although it tends 10 to delay the decision-making process, but the hope is 11 that what comes out at the end is better for everyone 12 concerned. 13 MEMBER ZERKER: Thank you very much, Mr. 14 McGee. 15 THE PRESIDING MEMBER: I just had one quick 16 question, Mr. McGee. That is you talked about the first 17 block and the rate that they set to try and recover 18 effectively the fixed charge. That's why it's higher 19 than the second block. Is there a minimum bill 20 provision in many of those rate structures? 21 MR. McGEE: Well, yes. Every utility has a 22 minimum bill and that's somewhere around the $6 range. 23 I think that's intended to cover the cost of issuing the 24 bill, reading the meter and that type of thing. 25 The minimum bill only recovers the costs that 26 are, you know, independent of any consumption. Yes. 27 THE PRESIDING MEMBER: The minimum bill is 28 structured to provide the costs of handling the || Vol. Pg.828  1 customer, but the costs of the line -- I imagine a large 2 proportion of the costs of the utility will be capital 3 related. The cost of the system existing, is that a 4 variable charge? 5 MR. McGEE: I think the only capital that's 6 recovered in that minimum bill is the capital cost of 7 the meter itself and the wire from the transformer into 8 the house if the utility did in fact pay for it. 9 This, by the way, was a point that I made in 10 the previous submission, that in many cases for the last 11 20 years, consumers completely unwittingly and 12 unknowingly, because the money was collected from the 13 developer, had in the price of the house paid for the 14 complete distribution system put in to serve them, yet 15 they paid the same rates as everyone else paid, which is 16 the rate parity double charging. 17 Once you get back in to try and include the 18 cost of the minimum distribution system in that monthly 19 charge, you are again into the double charging situation 20 because the customer has already paid for it. 21 THE PRESIDING MEMBER: You are into the 22 contributed capital issue. 23 MR. McGEE: It all ties into rates. If rates 24 are going to be set on an average investment per 25 customer, then contributed capital above that level is 26 quite legitimate. When a utility asks for 110 per cent 27 or 120 per cent contributed capital, that is not 28 appropriate. || Vol. Pg.829  1 THE PRESIDING MEMBER: Ms Kwik, is there 2 something further you wish to ask? 3 MS KWIK: Yes, Mr. Chair. Thank you. 4 I just wanted to clarify, Mr. McGee, when you 5 said that the recommendation of the task force was to 6 include the purchase, installation, testing, maintenance 7 of meters, meter reading and so on, basically sort of 8 from the meter downstream in the flat service charge, 9 that is correct. But the recommendation doesn't leave 10 it at that. It says that that component would be 11 included in the flat charge. 12 Also, the use of the incremental distribution 13 cost of .006 actually was a recommendation of the task 14 force. I just wanted to clarify that. In fact, it has 15 been consistent with their recommendation. 16 THE PRESIDING MEMBER: Thank you, Ms Kwik. 17 MS KWIK: Thank you. 18 THE PRESIDING MEMBER: Any other comments? 19 MR. McGEE: I am certainly aware of that. I 20 saw a major inconsistency between the recommendations 21 and what actually came out. As we mention, in their 22 final comment the actual number used for incremental 23 distribution costs by electric utilities in Ontario is 24 nowhere near 0.62 cents. It is much above that. 25 Preliminary calculations indicate to me it is 26 over one cent. When you start adding in market based 27 rates of return, it should probably go up to the 1.5 28 cent level. || Vol. Pg.830  1 MS KWIK: Perhaps you could include those 2 calculations if you are going to be filing a final 3 submission. Perhaps you could include those for us. 4 MR. McGEE: I could do that, but as you can 5 appreciate, there are some monstrous difficulties in 6 doing those calculations and I have extremely limited 7 resources available to me. I am going to be putting a 8 lot of qualifiers on them. 9 MS KWIK: Okay. I thought you had done the 10 calculations. 11 MR. McGEE: I have done the calculations, but 12 I know that I had to make certain assumptions in doing 13 it. It's an extremely easy calculation to do. It only 14 takes five minutes. All you need is the Ontario Hydro 15 Annual Report and municipal rates and comparative bills 16 and you can do it for "snap" (snaps fingers). 17 THE PRESIDING MEMBER: Mr. McGee, if you wish 18 to include it, it may be helpful, even if it has a lot 19 of qualifiers. 20 MR. McGEE: Yes. I will do that. 21 THE PRESIDING MEMBER: There just remains for 22 me to thank Mr. McGee, Mr. Wright, Ms Moore for 23 attending and for sharing with us their insights and 24 their help. If you are making a final submission, we 25 look forward to reading it. Certainly we will take into 26 consideration the comments and suggestions you made to 27 us today. 28 Thank you very much for coming. || Vol. Pg.831  1 MR. McGEE: Thank you. 2 THE PRESIDING MEMBER: I think we have to 3 break now. I have to break now. The reporters have 4 been here a long time. 5 Could we come back at half past two. That 6 gives about 40, 50 minutes. Is that all right? There 7 are still two presenters, Enbridge Consumers Gas and 8 MEA. Those parties, are they able to accommodate those 9 times? 10 MR. RITCHIE: Yes. We have spoken with them. 11 Yes, they are available this afternoon. I think that 12 time frame would fit their availability. 13 THE PRESIDING MEMBER: Thank you, sir. We 14 will get back at half past two then. 15 Thank you. 16 --- Luncheon recess at 1340 17 --- Upon resuming at 1440 18 THE PRESIDING MEMBER: Do you have anything, 19 Ms Kwik? 20 MS KWIK: No, there is not, Mr. Chair. Thank 21 you. 22 THE PRESIDING MEMBER: Then it is Enbridge 23 Consumers Gas. There is Ms Allan, and Ms Hare. If you 24 would you introduce yourselves, please 25 PRESENTATION 26 MS HARE: Thank you. 27 First of all, Enbridge is very pleased to be 28 here before the Board to discuss our views with respect || Vol. Pg.832  ENBRIDGE, Presentation 1 to the PBR Handbook. 2 My name is Marika Hare and I am employed by 3 Enbridge Consumers Energy Inc. as Director of Business 4 Development. With me is Stephen Cartwright, Manager of 5 Business Development also with Enbridge Consumers Energy 6 Inc. This is the division of Enbridge that is looking 7 to expand into electricity distribution. 8 We are going to be making a joint submission. 9 It is an Enbridge submission, so with me also from 10 Enbridge Consumers Gas is Judith Allan, Director, 11 Regulatory Policy Development. Enbridge Consumers Gas 12 is interested in this hearing with respect to regulatory 13 consistency between gas and electricity distribution. 14 Each of us has participated on one of the PBR task 15 forces. 16 We have already filed a written submission and 17 provided a summary of our oral presentation. What I 18 would like to do this afternoon is to highlight some of 19 our comments. I apologize in advance for referring to 20 notes, but I find it easier just to keep on track if I 21 am looking at some written notes. 22 As the Board knows, nearly all of Enbridge's 23 energy delivery infrastructure businesses in Canada and 24 the United States are regulated. The company has had 25 considerable experience in designing, implementing and 26 negotiating its way through a variety of PBR models, and 27 we draw on this experience in putting together our 28 position. || Vol. Pg.833  ENBRIDGE, Presentation 1 We believe our views on PBR are consistent 2 with the Board's policy. The Board has also received a 3 number of other submissions that list the general 4 principles and goals of an effective PBR framework, 5 notably the consultants' studies filed by the Consumers' 6 Association of Canada and Power Budd. These documents 7 highlight some of the principles that we believe are 8 essential for PBR. They include simplicity, 9 transparency, the need for positive incentives to 10 achieve productivity, equitable sharing of efficiency 11 gains between customers and shareholders, and a need for 12 a light-handed approach that minimizes the regulatory 13 process and expense. 14 Enbridge recognizes that the issues addressed 15 by Board staff are complex and that developing a PBR 16 framework that is effective for Ontario's diverse 17 electric distribution utilities poses unique challenges. 18 This PBR framework will need to meet the requirements of 19 the largest and the smallest utilities, those that have 20 already implemented strict efficiency programs and those 21 that have not, those that will continue to be owned by 22 municipalities and may or may not be run as for-profit 23 businesses, and those that are in private ownership. 24 So we recognize the challenge before the Board 25 and that the eventual PBR framework may be the result of 26 an evolving process. However, we believe that the Board 27 staff's draft PBR Handbook does not achieve the PBR 28 objectives established by the Board, and we submit needs || Vol. Pg.834  ENBRIDGE, Presentation 1 amendment to be effective and consistent with the 2 principles of the Energy Competition Act. 3 Enbridge believes that a less costly plan must 4 be developed that takes into account the pragmatic 5 concerns expressed by the caps mechanism task force 6 related to an electric distribution company's ability to 7 bear regulatory cost burden. 8 We suggest modification in four areas. These 9 include: a higher base ROE to reflect the higher 10 returns available from other industries in regulated 11 utilities with which Ontario electric distribution 12 companies will compete for equity capital and to reflect 13 the greater risks to which electricity distributors will 14 be exposed in the restructured Ontario energy market; a 15 lower threshold productivity offset factor we believe in 16 the order of, say, 0.3 per cent, to reflect the limited 17 potential for electric distribution company management 18 to achieve productivity gains during the short first 19 generation period and to establish a realistic standard 20 which offers some prospect of being exceeded rather than 21 imposing substantial risk to electric distribution 22 company shareholders of achieving the base ROE; urge 23 replacement of the multiple tier ROE caps with an ROE 24 dead band extending 300 basis points above the base ROE 25 with uniform sharing of all productivity gains above 26 this level at 50 per cent to customers and 50 per cent 27 to the utility shareholder; and, fourth, establishment 28 of a principle that productivity gains achieved during || Vol. Pg.835  ENBRIDGE, Presentation 1 the first generation will be carried over into the 2 second generation in the same sharing proportions as 3 applied in the first generation rather than being 4 rebased. 5 I would like to expand on each of these. 6 In terms of the initial revenue requirement, 7 Enbridge views that the proposed base ratemaking 8 structure on which PBR is overlaid is generally sound 9 except for the proposed base rate of return on equity of 10 9.75 per cent, which would reflect an equity premium of 11 about 375 basis points. 12 It is recognized this is a placeholder only. 13 However, Board staff has provided no basis for this risk 14 equity premium in its proposed target rate of return of 15 9.75 per cent. An appropriate starting point is 16 integral to the ability of utilities to earn a 17 reasonable return on shareholder capital and to maintain 18 financial viability. 19 The appropriateness of the base ROE can be 20 considered in two parts: first, the appropriateness of 21 Canadian regulated return benchmarks generally; and, 22 second, the relative riskiness of Ontario electricity 23 distribution. 24 On the first matter, Enbridge's experience is 25 that the generic ROE formula adopted by many Canadian 26 regulators have resulted in allowed returns which are 27 unattractive to suppliers of equity capital in 28 comparison to returns available from investments in || Vol. Pg.836  ENBRIDGE, Presentation 1 other industries or in regulated utilities. 2 Even if the level of Canadian generic rates of 3 return were appropriate, a larger premium we believe is 4 justified for the newly established electricity 5 distribution companies. These will generally be small 6 entities that will face new risks as the industry 7 transitions to the new environment. They will also face 8 new regulatory risks moving immediately to a PBR 9 environment without even any intervening time for 10 experience with the pure cost-of-service model. 11 The proposed base rate of return on 12 shareholder's equity would be inequitable to 13 shareholders and adversely affect the ability of 14 electric distribution companies to attract and retain 15 sufficient equity to maintain reliability and provide 16 service. 17 We have appended to our oral submission a 18 study that was completed by Navigant Consulting. This 19 consultant was requested to provide an independent 20 assessment of the Board's PBR Handbook. It wasn't 21 completed in time to append to our written submission 22 but we have included it with today's submission. 23 As you will see on page 5 of the consultant's 24 report, the authorized ROE is recommended to be set at 25 1 to 2 percentage points higher than the proposed level 26 of 9.75 per cent. 27 Turning to the productivity offset factor, 28 Enbridge views the proposed threshold productivity of || Vol. Pg.837  ENBRIDGE, Presentation 1 1.25 per cent as being substantially higher than 2 appropriate for a short term first generation framework. 3 The productivity offset factor as designed applies to 4 the entire revenue envelope, but in the short term more 5 than half of the electric distribution company's total 6 costs will consist of taxes, depreciation and other 7 capital costs which are essentially fixed and 8 non-controllable. 9 The proposed productivity factor was derived 10 on the basis of the reporting utility's total factor 11 productivity growth, which was approximately 1 per cent 12 for the period 1988 to 1997. But the structure of 13 industry costs will be much different in the future than 14 it has been in the last 10 years. The previous 10-year 15 period was marked by 3 per cent average inflation, 16 social contracts and wage rollbacks that made the 17 achievement of 1 per cent productivity much easier to 18 do. In the environment of lower inflation that is 19 expected going forward, this level of productivity 20 growth may be difficult to achieve. 21 It should also be recognized that there is 22 much greater scope to manage fixed costs over a 10-year 23 period than there will be over the short first 24 generation PBR period. 25 Board staff and the consultants made reference 26 to the large cash balances that many electric 27 distribution companies currently carry and that a more 28 efficient deployment of capital will help to achieve the || Vol. Pg.838  ENBRIDGE, Presentation 1 chosen productivity factor. While there may be some 2 utilities that this applies to, we would expect that the 3 majority of utilities will quickly move to a more 4 appropriate cash balance by paying out dividends upon 5 corporatization, thus reducing these cash balances. 6 Therefore, the only lever left to management 7 to achieve productivity gains will be the remaining 8 costs of operating and maintenance or general 9 administration. The productivity savings from these 10 costs would have to be a factor of several times the 11 specified total factor parameter. 12 For example, to achieve a 1.25 per cent total 13 factor productivity in the short term an electric 14 distribution company would have to achieve O&M 15 productivity of about 3 to 5 per cent, just to maintain 16 the base ROE before achieving any premium returns. 17 This is an unrealistic standard which imposes 18 substantial risk to electric distribution company 19 shareholders of even achieving the base ROE. 20 The addition of a stretch factor over and 21 above the historical average is particularly 22 inappropriate under these circumstances and simply 23 magnifies the unrealistic levels of short term O&M 24 productivity which would have to be achieved to keep the 25 shareholders whole during the first generation period. 26 Typically, stretch factors are incorporated 27 into PBR plans to account for accumulated 28 inefficiencies, information asymmetry and to assure a || Vol. Pg.839  ENBRIDGE, Presentation 1 commitment on the part of management to strive for 2 better performance. 3 Enbridge submits that there has been no effort 4 made to quantify the effects of informational asymmetry 5 and suggests that for a first generation PBR one of the 6 objectives is to overcome that asymmetry, not compensate 7 customers for its existence. 8 Furthermore, there is no evidence to suggest 9 that the electric distribution companies have 10 accumulated inefficiencies. In fact, there is reason to 11 believe that electric distribution companies in Ontario 12 have been very efficient relevant to their peers. This 13 point has been made in a number of the other 14 submissions. 15 For these efficient utilities which have 16 already had a focus and commitment to operational 17 efficiency as part of their business practices, there 18 will be less scope to introduce additional efficiency 19 enhancing measures. 20 In summary, Enbridge recommends that for the 21 first generation PBR period the threshold total 22 productivity offset factor should be set at a much lower 23 rate, say 0.3 per cent, which will require O&M 24 productivity at about .7 to 1.2 per cent. This is a 25 level which electric distribution company managers can 26 reasonable strive to meet and exceed, rather than a 27 level they are bound to fall short of in most cases. 28 The third point with respect to ROE caps. || Vol. Pg.840  ENBRIDGE, Presentation 1 The proposed first generation PBR structure is 2 a price cap structure with an ROE cap structure overlaid 3 on it. Based on experience with a variety of different 4 incentive structures, Enbridge views this combination as 5 complex and significantly restricting to achieve 6 efficiency and is, therefore, unlikely to achieve the 7 desired results. 8 In Enbridge's experience, the most effective 9 incentive mechanisms are those which are simple and 10 uniform with respect to the sharing of gains. In other 11 words, every dollar of productivity or efficiency gain 12 contributes partly to lower prices and partly to higher 13 shareholder returns, with the first dollar shared the 14 same as the last dollar. This is particularly important 15 where the magnitude of potential gain is unknown, as it 16 generally is at the initiation of a PBR program. 17 Uniform sharing ensures that no matter what 18 level of gain is achieved all stakeholders will be 19 winners and none will be losers. Customers and 20 shareholders may both be small winners together or both 21 may be big winners, but their interests are aligned. It 22 is also a structure that will be most easily understood 23 by customers. 24 Keeping it simple and trying to avoid bad 25 outcomes was mentioned numerous times by Board staff and 26 the consultants as their guiding principles in 27 developing the productivity factor in ROE relationship. 28 Enbridge believes that neither has been || Vol. Pg.841  ENBRIDGE, Presentation 1 achieved and recommends that the tiered ROE cap 2 structure be replaced with a simpler model, one which 3 incorporates fixed uniform sharing proportions above the 4 dead band of 50 per cent to the utility and 50 per cent 5 to customers and one which facilitates a strong win-win 6 result on which to build the second generation PBR. 7 Fourth, rebasing. 8 The Draft PBR Handbook provides no guidance on 9 how gains achieved during the first generation will be 10 carried over into the second generation. This will 11 substantially inhibit the incentive for electric 12 distribution company management to seek productivity 13 gains until the rules of the game are known for the 14 second generation. So constrain the effectiveness of 15 the first generation as a learning experience even if 16 the ROE cap modification previously discussed is 17 affected. 18 An important ingredient in the success of the 19 incentive tolling agreement for Enbridge's National 20 Energy Board regulated mainline pipeline was that the 21 principles were established at the outset for 22 renegotiating the second five-year term. 23 In particular, while many of the parameters 24 were open for renegotiation, such as inflation index and 25 the sharing proportions for further second term gain, 26 the first term gains were not subject to rebasing. 27 These principles provided management with the incentive 28 to maximize productivity gains throughout the first term || Vol. Pg.842  ENBRIDGE, Presentation 1 with the result that significant gains were achieved -- 2 we are talking in the order of $87 million pre-tax -- 3 and these gains were shared between customers and the 4 shareholders and a favourable environment was created 5 for extending the agreement. 6 Customers of the pipeline resoundingly 7 endorsed the effectiveness of this arrangement by 8 extending their agreement for a further five-year term, 9 for the years 2000 to 2004, with no rebasing of the 10 gains achieved during the initial five years. 11 Provided the sharing mechanism is balanced and 12 ensures a fair allocation of benefits during the term of 13 the PBR plan, there should be no concern with rebasing 14 at the end of the term. 15 Rebasing serves to provide an opportunity to 16 examine a utility's cost structure at the end of the PBR 17 term to ensure that the utility was not more successful 18 than what had been reflected in its productivity offset. 19 However, monitoring and reporting guidelines ensure that 20 the regulator is able to see whether a utility's 21 financial performance suggested that something was not 22 balanced in the PBR structure. 23 Additionally, an appropriately structured 24 sharing mechanism provides customers a fair share of the 25 benefits all along rather than at the end of the PBR 26 plan. 27 Enbridge recommends that in conjunction with 28 the uniform sharing of gains above the ROE dead band, || Vol. Pg.843  ENBRIDGE, Presentation 1 which we have already discussed, all first generation 2 PBR gains be carried forward in to the second generation 3 with the same allocation between customers and 4 shareholders as in the first generation. This principle 5 should be established at the outset. 6 There are other aspects of the draft PBR 7 structure that Enbridge believes would benefit from 8 further refinement, including service quality 9 indicators, monitoring and reporting requirements, the 10 proposed inflation index and the consideration of a 11 shared savings mechanism for DSM programs. 12 The Board has received a number of submissions 13 on these important topics and we have nothing further to 14 add on the comments already made. 15 In conclusion, based on its experience with 16 incentive structures for regulated utilities, Enbridge 17 is confident that the modifications recommended in this 18 submission will result in a structure that will more 19 effectively achieve the Board's purposes. 20 Apart from these specific recommendations, and 21 recognizing the very significant changes which electric 22 distribution company management will have to cope with, 23 Enbridge respectfully urges the Board to adopt a first 24 generation structure which is very simple, provides a 25 clear and strong positive incentive to achieve 26 productivity gains, benefits customers and does not 27 impose significant risk of shortfalls from the base ROE. 28 Once again, Enbridge would like to thank the || Vol. Pg.844  ENBRIDGE, Presentation 1 Board and Board staff for the opportunity to be part of 2 the process, and we hope that our comments and 3 recommendations are of assistance to the Board. 4 THE PRESIDING MEMBER: Thank you. 5 Do Board staff have any questions? 6 MS KWIK: No we do not, Mr. Chair. Thank you. 7 THE PRESIDING MEMBER: I will start off with a 8 few and then I will pass it on to my colleagues. 9 You mentioned the rebasing of the IPL -- I'm 10 sorry, is it Enbridge IPL Pipeline? 11 MS HARE: Enbridge Pipeline. 12 THE PRESIDING MEMBER: Enbridge Pipeline. 13 How many years was the first term? 14 MS HARE: The first term was five years and it 15 was renegotiated for a further five years. 16 THE PRESIDING MEMBER: What was the 17 productivity offset in the first term? 18 --- Pause 19 MS ALLAN: The agreement started with a 20 negotiated base revenue requirement and didn't have an 21 explicit productivity factor. It was a negotiated with 22 APP, the Association of Petroleum Pipelines. 23 THE PRESIDING MEMBER: So it's a negotiated 24 agreement on the revenue requirement and then a rate of 25 return earnings cap above which any additional earnings 26 would be shared. Is that what it is? 27 MS ALLAN: No. It is just a revenue 28 requirement and then savings relative -- the revenue || Vol. Pg.845  ENBRIDGE 1 requirement moved with CPI year by year. So any savings 2 from that revenue requirement line -- which was net of 3 tax, so basically what revenue requirement plus tax gave 4 you tolls. 5 So, in effect, it was a formula revenue 6 requirement and any difference between that formula 7 revenue requirement and the actual revenue requirement 8 became the savings. That savings was split 50/50. 9 There is a return on equity in the 10 renegotiated agreement, but the original agreement ran 11 straight off this formula revenue requirement. 12 THE PRESIDING MEMBER: And this is a 13 negotiated agreement between the customers of the 14 pipeline and the company. 15 MS ALLAN: That's correct, the Canadian 16 Association of Petroleum Producers. 17 THE PRESIDING MEMBER: This was then approved 18 or accepted by the National Energy Board. Is that 19 correct? 20 MS ALLAN: That is correct. In fact, when it 21 went to the National Energy Board, there was a change in 22 the monitoring and reporting to move the monitoring and 23 reporting to that which was more appropriate to the 24 agreement. 25 So there was a movement away from some 26 quarterly reporting, if I remember correctly, which the 27 NEB also had to approve. 28 THE PRESIDING MEMBER: Basically, this was || Vol. Pg.846  ENBRIDGE 1 starting from a cost of service type base, where the 2 information was available and had been tested in 3 previous rate applications. 4 MS ALLAN: The first agreement, yes; the 5 second was not. 6 THE PRESIDING MEMBER: The second thing is: I 7 think we started off by talking about the return on 8 equity and suggesting that a higher than the 9.75 per 9 cent should be available to the electrical distribution 10 utilities and that is one of the issues related with the 11 risk or relative risk of the distribution utilities with 12 that of another entity. 13 I was wondering whether there was any comment 14 as to your perception of the relative risk of a 15 distribution utility in the electricity sector and that 16 of a gas distribution utility. 17 MS ALLAN: In the electric sector I think 18 there is an increased risk, simply given the 19 restructuring that the electricity sector will be 20 undergoing in the next few years. We have noted the 21 controversy around contributed capital, for example. 22 There also has been controversy around transition costs 23 in some of the submissions. 24 For example, VECC has suggested that there 25 would not be in some cases complete recovery of 26 transition costs. They have put forward a benchmarking 27 proposal. 28 These are issues that are coming to the fore || Vol. Pg.847  ENBRIDGE 1 at this point. We believe there will be many more such 2 issues simply given the magnitude of the change, the 3 fundamental assumptions that are being revisited, and 4 therefore that leads us to a conclusion about the 5 relative risk. 6 THE PRESIDING MEMBER: This sounds largely 7 like regulatory risks. 8 MS HARE: Another risk that we are not sure 9 how it will unfold is the fact that in gas we do have 10 franchise agreements. In electricity distribution there 11 is no such thing as a franchise non-exclusive agreement. 12 So whether or not in fact there is some competition from 13 new subdivisions as to who is the supplier in terms of 14 the distribution itself may create a risk. 15 THE PRESIDING MEMBER: In the context of the 16 delivery or in the context of the commodity? 17 MS HARE: In the context of delivery. 18 THE PRESIDING MEMBER: I'm sorry, I don't 19 quite understand. 20 You are suggesting that somebody else made 21 those on the electric power line to do it? 22 MS HARE: That is our understanding with 23 non-exclusive franchises with electricity; that if a new 24 subdivision is being built, it could be served not by 25 the local distribution company but by a new distributor. 26 MEMBER VLAHOS: And it will be able to compete 27 with a depreciated system, an existing system? 28 MS HARE: I'm not sure. || Vol. Pg.848  ENBRIDGE 1 MS ALLAN: If it is a neighbouring utility, 2 perhaps, Mr. Vlahos. I think that is part of the 3 uncertainty at this point. 4 THE PRESIDING MEMBER: So essentially the 5 relative risk reflects the uncertainty of the framework 6 to be put in place. Is that the issue? 7 MS HARE: I think that is a big part of it, 8 but we do think there are some other risks. 9 THE PRESIDING MEMBER: In talking about the 10 ROE cap, you also talked about a dead band zone. Was I 11 correct that you said that the dead band zone would be 12 300 basis points, and then a 50:50 sharing above it? 13 Is that what you are proposing? 14 MR. CARTWRIGHT: That is correct. 15 THE PRESIDING MEMBER: For the sake of 16 numbers, if was 10 per cent and they earned up to 13 per 17 cent, no sharing, but above 13 per cent, a 50:50 18 sharing. 19 MR. CARTWRIGHT: That is correct. 20 THE PRESIDING MEMBER: And no sharing if they 21 are below 7 per cent. It is all to the account of the 22 utility if it is anything below 10 per cent. 23 MS HARE: Yes. 24 MS ALLAN: Mr. Dominy, if I could go back to 25 the previous discussion, there has also been a fair 26 amount of discussion around the one size fits all. I 27 think that whereas the Board on the gas side has 28 indicated it will be looking at PBRs that are tailored || Vol. Pg.849  ENBRIDGE 1 to the individual circumstances of the utilities, I 2 think there is an additional risk on the electricity 3 side that if we go with a one size fits all, there is 4 going to be a risk for an individual utility that that 5 PBR plan might not be quite as suitable. 6 For example, Ms Hare mentioned that if you are 7 already a very efficient utility, your scope for 8 delivering the productivity gains, since the 1 per cent 9 number is an average, by definition means that there is 10 greater risk to get to the 1 per cent for some utilities 11 than for others. 12 THE PRESIDING MEMBER: I was interested in how 13 you arrived at the .3 per cent productivity factor 14 number. 15 MR. CARTWRIGHT: It is essentially 16 backtracking -- if you equate the 1.25 to what you would 17 need to achieve in terms of changes to your O&M or 18 General and Administration expense, we see it as being 19 roughly two to three, perhaps in some cases four times 20 greater, given that the other costs are essentially 21 fixed for that short term. 22 If you work that back from an historical 23 average of 1 per cent productivity factor, taking that 24 two to three times normal, a .3 per cent productivity 25 factor on revenue would make an achievable one -- I 26 believe we used .7 to .2 per cent actual productivity 27 change in the controllable costs that you have. 28 THE PRESIDING MEMBER: As I understand what || Vol. Pg.850  ENBRIDGE 1 you are telling me, in order to achieve a .3 on total 2 revenue, you need to achieve three times that on O&M; 3 therefore, you divide the one by three. 4 MR. CARTWRIGHT: That's correct. 5 THE PRESIDING MEMBER: When you talked about 6 the rebasing and you said the rules of the game were put 7 in place, was that the very first Enbridge Pipeline 8 Services application, or was it the start of the second 9 one? 10 MS HARE: No, it was with the very first. So 11 they understood with the first generation PBR what the 12 rules would be for the second generation in terms of 13 rebasing and what parameters were open for renegotiation 14 and which ones would not be. 15 THE PRESIDING MEMBER: So when you come to 16 calculate, I am assuming in the second phase of the 17 Enbridge Pipeline Services arrangement, the implied 18 return on equity in the rates going forward, you take 19 out in the calculation of what it is the 50 per cent of 20 the savings that have been received. 21 Is that what they do? 22 MS ALLAN: I am just trying to check here, but 23 I believe what they simply did was just kept the thing 24 going. Since the savings had been passed to customers 25 every year, that has shown up in tolls and therefore in 26 the revenue requirement. So you just move forward from 27 that base. Rather than seeing a discontinuity as you 28 move to a cost of service based revenue requirement, you || Vol. Pg.851  ENBRIDGE 1 stayed on the revenue requirement out of the original 2 formula. 3 THE PRESIDING MEMBER: Dr. Zerker will take 4 over now. 5 MEMBER ZERKER: Good afternoon. 6 Let me go back to, Ms Allan, your comments 7 about the regulatory risks. I just want to be clear 8 that the risks that you mentioned, which was contributed 9 capital or -- I can't remember, IPI maybe. 10 MS ALLAN: Transition costs. 11 MEMBER ZERKER: Transition costs, right. All 12 of these are part of the draft Handbook. This is by no 13 means the final version. Certainly we don't yet have a 14 final version. To the extent that you are talking about 15 risks that are regulatory, risks that are not real as 16 yet, I am asking you in fact whether or not you can take 17 that into account. 18 MS ALLAN: I guess I would have two comments. 19 First, I used those as examples of controversy that have 20 already started to surface. I wasn't pointing 21 specifically to those. In my view, those are examples. 22 I guess I come back to it's trite to say that 23 the risk is something that is always out there. 24 Specifically once you have actually gotten hit, then you 25 look and you say "Well, the Regulator may treat you in a 26 certain fashion on some other items". 27 There is uncertainty around so many factors as 28 we move forward that leads me to that conclusion. It's || Vol. Pg.852  ENBRIDGE 1 the magnitude of the change that we are looking at where 2 there is a risk that the shareholder will be forced to 3 bear costs. That is not being compensated for in the 4 calculation of return. 5 I'm not a rate of return expert, but I know 6 the risks that you face as you try and operate a 7 business as you go forward. For example, I notice that 8 you were disagreeing with Ms Hare when it came to the 9 whole question of non-exclusive franchises. I know that 10 the Board has, for example, in natural resource gas 11 territory, there are some non-exclusive franchises at 12 the opportunity municipality level. Yes, everybody 13 understands that. That's not a factor that adds to 14 additional risk. 15 Until we know what exactly it is that the 16 Board means by non-exclusive licences in the electricity 17 sector and how that compares to the franchise system 18 that we know and we understand on the gas side, as long 19 as you have got those question marks, until you figure 20 out how these things are going to work, yes, there is a 21 risk there. 22 MEMBER ZERKER: You see, what I'm confused 23 about is the concept of timing because what you are 24 talking about in terms of a higher ROE is post-decisions 25 or some of these decisions that you are concerned about. 26 If you tell me that there are regulatory 27 risks, I suppose that would be true in all instances 28 where you have monopoly structures that are regulated. || Vol. Pg.853  ENBRIDGE 1 I suppose that changes can occur, but it seems to me 2 that you are mixing apples and oranges when you take the 3 uncertain conditions now that will be put to a large 4 expense, the ones that you are concerned about will be 5 defined before we get to the 9.7 per cent. 6 That's where my confusion lies. I think that 7 at least in terms of timing, there is an apples and 8 orange problem here. 9 MS ALLAN: I understand the point you are 10 making. I guess that's why I was pointing out these out 11 as examples. Yes, those will be resolved. 12 The other comment I would make, as Ms Hare 13 mentioned, typically the returns for regulated utilities 14 in the U.S. are much higher than they are in Canada. In 15 part, that has been between regulatory commissions have 16 looked at the restructuring of the electricity sector 17 and have made an allowance for a higher risk. 18 MEMBER ZERKER: Not on the basis of regulatory 19 problems or on the basis of regulatory problems? 20 MS ALLAN: I think it is -- 21 MEMBER ZERKER: What I'm asking for is your 22 analysis of what gives the electricity industry its 23 uniqueness in terms of risk. That's what I really am 24 after. Regulatory risk I put into the category as part 25 and parcel of a monopoly structure that is at the same 26 time assured a return or at least more so -- let me not 27 say it's a guarantee, but more so than a private 28 enterprise that's just out there in the market against || Vol. Pg.854  ENBRIDGE 1 its competitors. 2 Other than that, what other risks are you 3 talking about that are beyond the regulatory issue? 4 MS ALLAN: I think that, to answer your first 5 question, in the U.S. it has been a recognition of 6 increased competition, but also the interaction between 7 regulation and competition. You are right, it is not 8 solely a regulatory issue. 9 I guess if I can put it in very, very blunt 10 terms, when the Regulator has to make as many decisions 11 as this Regulator is going to have to make over the next 12 three to five years, yes, you will be making some of 13 them very soon, the Regulator has that many more 14 opportunities to get it wrong. That's what I'm focusing 15 on is the magnitude of the change. 16 MEMBER ZERKER: Okay. 17 MS ALLAN: And the sheer number of decisions 18 that are facing the Regulator when you are looking at 19 this fundamental a change. 20 MEMBER ZERKER: So then I would conclude from 21 your remarks that what you feel the Ontario electricity 22 industry is facing, the unique characteristic is that it 23 is in the process of transformation, of major 24 transformation, whether or not it's by Regulator 25 decision or by all the other legal and economic changes 26 that are underway. 27 MS ALLAN: That's fair. 28 MEMBER ZERKER: Okay. Now, I would like to || Vol. Pg.855  ENBRIDGE 1 ask Ms Hare a question going back to this 3.3 per cent 2 factor. 3 We have had some discussion from other 4 intervenors that have submitted the proposal for a lower 5 PF. Nobody even came close to what you are suggesting. 6 All of them argued on the same basis, that is to say 7 that there are rigidities because of the kind of 8 industry it is and the capital intensity, but the lowest 9 that I think, and you can correct me if I'm wrong 10 because I may not have remembered everybody's 11 submissions, but it seems to me that .8 per cent was the 12 lowest one that we had before us. 13 It seems a stretch, a big stretch, to get to 14 your .3 per cent. 15 MS HARE: We used .3 as an example. We don't 16 really know what the exact number should be. We didn't 17 have all of the data that the Board staff did. What we 18 did do, as Mr. Cartwright suggested, we looked at what 19 we thought the percentage of controllable costs were. 20 In considering the short period and the 21 ability to manage those costs, we thought that something 22 significantly lower than the 1.25. What we said was in 23 the order of .3, but maybe it's .5, maybe it's .6, but 24 we think 1.25 is not achievable. 25 MS ALLAN: I think the other difference, Ms 26 Zerker, as Ms Hare indicated in her remarks, we were not 27 looking at an average productivity target which the 28 Board staff numbers and the discussion of others have || Vol. Pg.856  ENBRIDGE 1 been focused on. We came at it from the perspective of 2 a target that we believe people can meet and then we 3 laid out an explicit sharing mechanism. 4 I know that others have mentioned a sharing 5 mechanism as well, but we want to make sure that there 6 is an incentive there, an incentive that will work for 7 most, if not all, of the utilities. 8 You have heard submissions over the last 9 couple of days to the effect of all of the other things 10 that are on the agendas of particularly the 11 municipalities. It's our concern that the proposal that 12 is here that productivity will drop to the bottom of the 13 agenda of the electric utilities if they do not perceive 14 that there is an incentive there for them. 15 So what we are trying to do is to create an 16 incentive that will work for all utilities. 17 It may be that there have been questions 18 around the dead band, but those are all mechanisms. You 19 are determining the sharing between the ratepayer and 20 the shareholder. You can play with all three of those 21 factors, but we think that you should set them in such a 22 way that you create an incentive for as many utilities 23 as you can and, then, if that means that there is going 24 to be a significant amount of sharing, maybe the bottom 25 line, if that turns out to be a .8 or a .9 per cent 26 productivity factor when you are done, it is just simply 27 delivered to ratepayers in a different way through the 28 combination of a .3 productivity factor and a sharing. || Vol. Pg.857  ENBRIDGE 1 MEMBER ZERKER: But your sharing is only on 2 the upper end, right? Your proposal for sharing is only 3 on the upper end. I mean, you are not going to lose 4 anything if you go below 7 per cent. 5 MS ALLAN: That is our proposal. Yes, that's 6 correct. 7 MEMBER ZERKER: There have been proposals, as 8 you probably know, that if you gain you gain on the 9 upper end along with the customers and if you lose you 10 lose as well on the lower end. 11 MS ALLAN: If you do not put in a sharing, it 12 is the shareholder that loses 100 per cent below the 7 13 per cent anyway. 14 MEMBER ZERKER: But the asymmetry of your 15 system differs from some other symmetrical ones. 16 MS ALLAN: If you make it symmetric, it then 17 flows to the benefit of the shareholder. Right now, if 18 there is no sharing below 7 per cent, that is to the 19 detriment of the shareholder. 20 MEMBER ZERKER: Only to the detriment of the 21 shareholder? 22 MS ALLAN: If there is no sharing below 7 per 23 cent. 24 MEMBER ZERKER: I'm talking about sharing of 25 losses. 26 MS ALLAN: Yes, because then you are not 27 asking ratepayers to share in the losses. 28 MEMBER ZERKER: I take your point. That's || Vol. Pg.858  ENBRIDGE 1 true. 2 There is one other point before I pass on to 3 Mr. Vlahos. There was one other point. 4 Oh, yes. I get again and again the argument 5 that the efficient firms are penalized because they have 6 been efficient and therefore it will be harder for them 7 to continue to increase their efficiency. The problem I 8 have with that is that theoretically you can argue that 9 and there is a difference between theory and practice. 10 Apparently, we have some evidence that in practice that 11 is not true. 12 It does sound logical, and theoretically 13 economists could tell you why, but that doesn't mean 14 that we can always go out into the real world and find 15 that is theoretical argument. It is a model, but it 16 doesn't necessarily follow. The consultants, at least, 17 indicated that that doesn't seem to follow in the past, 18 that the efficient firms continue to be the efficient 19 firms over time. 20 MS ALLAN: I think that in Ontario, 21 particularly in the period when Ontario Hydro was having 22 very high percentage increases -- and I'm going back to 23 the period before the recent rate freezes -- there was a 24 very definite pattern where some municipalities would 25 say, "Okay, we have an 8.6 per cent Ontario Hydro 26 increase and so therefore our rates are going to go up 27 8.6 per cent and we will point the finger at Ontario 28 Hydro", where other municipalities -- and in my view || Vol. Pg.859  ENBRIDGE 1 this is one of the things that has led to the cash 2 balance situation that Board staff was focused on -- 3 other municipalities, particularly the municipalities in 4 smaller towns, the one-industry towns, the northern 5 towns, said, "Our councils will not stand for that. We 6 are going to hold our costs as tightly controlled as we 7 can and we are going to pass on the Ontario Hydro 8 increase so we will have, let's say, a weighted average 9 of 8.2 per cent or 7.8 per cent." 10 Some of the municipalities that passed on the 11 whole 8.6 per cent then turned around and built 12 buildings. You can look -- particularly in Metro 13 Toronto, you go and look at a lot of PUC buildings. 14 They all date from that era of very high Ontario Hydro 15 increases, and their costs tended to creep up because 16 their rates were creeping up. Then you moved into an 17 environment where you had social contracts, you had very 18 tight wage restraint. 19 We haven't had what I would call normal 20 electric utility ratesetting in this province, but we 21 have a lot of these anomalies. You can go to one 22 utility that has a certain cost per customer, you go to 23 the next utility -- you can't explain the differences. 24 I know Board staff has seen a lot. You can see from 25 their comments in the PBR Handbook, the technical 26 conference, there is a lot of variation. 27 This issue of lower productivity factors for 28 more efficient utilities also came up in the context of || Vol. Pg.860  ENBRIDGE 1 the Enbridge Consumers Gas targeted PBR. The 2 consultants in that proceeding, including the 3 consultants for the intervenors, indicated that on 4 average it is true. As you point out, like all 5 averages, there are times when it doesn't apply and 6 there are times when it does apply. 7 I guess the expression in the PBR literature 8 is the "low-hanging fruit". 9 MEMBER ZERKER: I'm sorry, I missed it. 10 MS ALLAN: The expression in the PBR 11 literature is the "low-hanging fruit". 12 MEMBER ZERKER: Oh, yes. We have heard a lot 13 about hanging fruit. 14 MS ALLAN: Yes. I think that there will be 15 places where the more efficient utilities have taken the 16 low-hanging fruit. 17 I think another factor is simply the 18 productivity culture, the mind-set within the utility 19 and that that would be one of the factors that would 20 lead to the point you were making being true, that if 21 you have a utility that has been more efficient on 22 average it will tend to be more efficient as you move 23 forward because it has that mind-set. 24 When we have looked at benchmarking studies in 25 the U.S. there is one utility in Illinois that comes out 26 head and shoulders ahead of everybody else. It is 27 simply because they have that productivity mind-set. 28 They are focused on low cost to the customer. They are || Vol. Pg.861  ENBRIDGE 1 focused on being very efficient. They pride themselves 2 on being very efficient. 3 But that having been said, that leads me to 4 two conclusions. One is, in general, it's true. You 5 are going to penalize -- regardless of what level of 6 productivity factor you bring in -- you are going to 7 penalize those utilities that have undertaken certain 8 productivity initiatives. 9 I come back to the culture thing. I think the 10 most important thing the Board can do is to make sure it 11 creates an incentive so we can get the culture change. 12 There is going to be so much culture change going on 13 within the electric utilities. We want to make sure 14 there is a productivity focus there as well. 15 MEMBER ZERKER: Isn't that precisely what the 16 objective of a PBR approach is? Aren't we looking for 17 making a lot of these firms into good, efficient 18 culture-bound utilities? Isn't that the objective 19 there? 20 I know that what you also are doing is helping 21 us to decide how to do it best, but just in terms of the 22 principle, isn't that what we are after? 23 MS ALLAN: It is possible to design a PBR that 24 has less incentives than the current cost-of-service 25 methodology. For example, under the current 26 cost-of-service methodology if the shareholder is 27 efficient during the year he gets to keep the balance, 28 he gets to keep those savings for the balance of the || Vol. Pg.862  ENBRIDGE 1 year. If, however, you rebase at the end of each year, 2 for example, historic test ratemaking, that has less 3 incentive than the current one-year ratemaking. 4 I think that the incentive power of various 5 PBRs varies immensely. There is also another objective 6 that we have seen here and that is to minimize the 7 burden on the regulator and on the regulatory staff. 8 I think you have to decide what exactly are 9 your objectives. I see some conflicting objectives 10 here. 11 One is, as I mentioned, you minimize the 12 regulatory burden. 13 The second is, the need to collect the 14 information as we move forward into the second PBR. 15 There is a lot of information collection within this PBR 16 that is going to add a lot of costs but really is there 17 for the objective of the second PBR. 18 The third is the incentive to deliver 19 productivity savings. 20 You, the Board, have to decide how you are 21 going to meet each one of those objectives. 22 You can design a PBR that has absolutely no 23 incentive. The easiest way to do it would be a very 24 high productivity that most utilities have very little 25 chance of making and they will just simply not make 26 their market-based rate of return and they will, in 27 effect, turn their backs on the PBR. 28 MEMBER ZERKER: Or, on the contrary, it will || Vol. Pg.863  ENBRIDGE 1 stimulate them to become more efficient. 2 MS ALLAN: We are looking at a situation in 3 which they are increasing their returns now, most of 4 them. So it becomes a question of: If we have to move 5 a mountain before we can make any additional returns, 6 I'm sorry, the mountain is not on our priority list. 7 I am exaggerating, and I recognize I am 8 exaggerating. 9 MEMBER ZERKER: No, I think that we could 10 debate this and that is not what we are here for. 11 But I do want to ask Ms Hare one question. 12 At the opening of your statement you talked 13 about simplicity as a value. Then I look at your 14 recommendations and I would appreciate if you would tell 15 me how by changing the numbers you are going to make it 16 more simple? 17 MS HARE: Well, I think actually there are a 18 number of aspects to our proposal that make it more 19 simple. I think doing away with a tiered structure and 20 going instead with a dead band and any anything above 21 that shared 50/50 with customers is much simpler and 22 easier to explain to customers than a tiered structure 23 and choosing a productivity factor in advance and then 24 having a different return. 25 MEMBER ZERKER: Any other parts to the story 26 of simplicity here? 27 MS ALLAN: In the consultant's report, for 28 example, we have recommended -- or the consultant has || Vol. Pg.864  ENBRIDGE 1 recommended fewer service quality standards from the 2 point of view of focusing in on simplicity. 3 We also felt that if we came in and said the 4 simplest thing you could do would be to go to something 5 like the Enbridge Pipelines deal, that would be very 6 simple, but we felt that the discussion so far in this 7 proceeding has been around productivity factors, has 8 been around earnings sharing mechanisms and we didn't 9 want to be so far out of the discussion that everybody 10 would say, "Fine, thanks, but you are just not in this 11 ballpark" and turn the page and not pay a lot of 12 attention to the submission. So we focused in on what 13 was being discussed. 14 MEMBER ZERKER: Thank you both. 15 Those are my questions for now. 16 THE PRESIDING MEMBER: Mr. Vlahos? 17 MEMBER VLAHOS: Thank you, Mr. Chairman. 18 Ms Hare, just one question: You started your 19 statement by posing a question as to you have no 20 information as to where the 9.75 per cent has come from. 21 I think you also mentioned that it is your information 22 this reflects a risk premium of 375 basis points. The 23 rest would be just a long-Canada forecast and that was, 24 I guess, at the time the PBR Handbook was prepared. 25 Now, your submission talks at length about the 26 need to go to a higher risk premium. 27 As you may know -- I'm sure that Ms Allan 28 knows -- there was a decision of the Board dealing with || Vol. Pg.865  ENBRIDGE 1 the Ontario Hydro Services, both transmission and 2 distribution, just a short few months ago. As I 3 understand it there was some evidence, I'm not sure how 4 extensive it was but I believe there was evidence filed 5 by certain parties' expert witnesses as to the 6 appropriateness of the risk premium and the Board has 7 made a decision as to what the appropriate level is for 8 at least those two companies for now, for the time 9 being. 10 I was just wondering whether the Board has 11 anything else now to go back to and rely on that 12 information as opposed to what the Board has heard at 13 length and evaluated in the case of Ontario Hydro 14 Services companies? 15 MS HARE: That would assume that the risk for 16 Ontario Hydro Services Company with the number of 17 customers they have and the size of the organization, 18 that that risk premium in running their business is the 19 same as for today's 250 municipal electric utilities, 20 which I would think is not the same risk. 21 What we were looking for was some explanation, 22 some assessment as to how that risk was arrived at. 23 I would submit that it is not the same for 24 Ontario Hydro Services Company as for the municipal 25 electric utilities. 26 MEMBER VLAHOS: All right. But I guess my 27 question is: What do we have on the record as to what 28 may be the risk profile of Ontario Hydro Services, || Vol. Pg.866  ENBRIDGE 1 distribution in this case, vis-a-vis the other 250-plus, 2 some of them being quite sizeable, some less so. 3 I just don't know where to go to. We do have 4 your submission, I just need some help. 5 Is it an arbitrary number that we can say that 6 375 basis points represents the absolute minimum and 7 then work from there? 8 MS HARE: Well, you see, that is an area that 9 we thought should be explored in more depth and that 10 didn't get very much discussion in the staff papers. 11 So we are submitting that it is too low and 12 something that should be reviewed before the final 13 document is issued. 14 MEMBER VLAHOS: I see. So your recommendation 15 is for a review of that risk premium and not necessarily 16 go to "X"? 17 MS HARE: Yes. What we have filed is the 18 Navigant report which suggests something in the order of 19 1 to 2 per cent higher. They base that on their review 20 of other jurisdictions of other utilities under a PBR 21 framework. 22 MEMBER VLAHOS: All right. 23 Thank you very much. 24 --- Pause 25 THE PRESIDING MEMBER: I did note that among 26 the list of documents that staff had discussed with task 27 forces there was a paper, I believe -- I think Ms Kwik 28 can correct me on this -- that discussed the || Vol. Pg.867  ENBRIDGE 1 determination of market issues. 2 MS KWIK: Yes, there was, Mr. Chair. 3 There was a report that was prepared by Dr. Bill Cannon 4 for us. 5 THE PRESIDING MEMBER: There was some 6 discussion this morning with Mr. Roman regarding the 7 lack of what he sees incentive -- or the incentive of a 8 utility not to go after productivity improvements and to 9 put themselves in a position of creating an opportunity 10 to make gains from productivity improvements in the 11 future and thereby making themselves an attractive 12 prospect for acquisition by a third party and thereby 13 perhaps getting a premium in the price that was offered 14 for the utility by a third party to a municipality. 15 I wonder whether you could comment on that, 16 because I took from Ms Hare's opening statement that her 17 company, or the company she represents, was in the 18 business of getting into the electricity distribution 19 area. 20 So I wonder whether you could comment on that 21 comment? 22 MS HARE: As a first comment, I would find it 23 difficult to believe that any utility or its municipal 24 shareholder would purposely be inefficient and keep that 25 inefficiency going just for the purpose of acquisition. 26 But be that as it may, this exactly is why we 27 think that if the rules for second generation PBR are 28 known at the outset and there is no rebasing that kind || Vol. Pg.868  ENBRIDGE 1 of game-playing wouldn't occur. 2 THE PRESIDING MEMBER: Okay. Thank you. 3 --- Pause 4 MEMBER VLAHOS: Ms Hare, based on Judy Kwik's 5 clarification as to the source of the risk premium, were 6 you aware of that background paper? 7 MS ALLAN: That's the report that was done by 8 Dr. Cannon. Yes, we were aware of that. 9 MR. CARTWRIGHT: Dr. Cannon's paper focuses 10 more on the technique of how it is arrived at, the 11 number, and using Canada bonds and then a premium. But 12 again, the final number has only been given as a 13 placeholder right now. The final risk premium has not 14 yet been determined, as I understand it. 15 MS KWIK: That's correct. 16 MEMBER VLAHOS: I think it is clear to 17 everyone except myself. The 9.75 per cent is a 18 placeholder. Is the risk premium a placeholder? 19 Ms Kwik...? 20 MS KWIK: Yes, the whole thing is a 21 placeholder. 22 MEMBER VLAHOS: The whole thing; that is, both 23 components. 24 MS KWIK: Yes. The considerations that have 25 been pointed out by this panel in terms of the risk 26 premium have not been considered. 27 MEMBER VLAHOS: Thank you for that 28 clarification. || Vol. Pg.869  ENBRIDGE 1 MEMBER ZERKER: I have just one comment, 2 Ms Allan. You notice that I was shaking my head about 3 the possibility of having two competing distribution 4 systems in one area. Of course, that negates the whole 5 principle, the whole concept of monopoly and therefore 6 would not need regulation if in fact that was the case. 7 That is fundamentally why, in principle and in 8 actuality, there is no logic to having competing 9 distribution systems from an economic point of view. 10 MS HARE: We are not implying that there would 11 be two sets of wires down the same street. But in 12 rapidly growing communities, in looking at the area that 13 could be served by that LDC, if there is a subdivision 14 being put in, the way we understand it now there is 15 nothing to stop that developer from contracting with 16 somebody else to do the installation and then the 17 billing and have the distribution. 18 MEMBER ZERKER: That's always been true. We 19 can still do that. We can do it under the old regime 20 and we can do it under the new regime. That does not 21 change the regulatory aspects of a distribution system. 22 MS HARE: But I mention that in context of gas 23 distribution versus electricity distribution, and is 24 there a greater risk. 25 MEMBER ZERKER: I still would quarrel with 26 that position. If you want to know why, we will talk 27 about it another time. 28 THE PRESIDING MEMBER: That does lead me to || Vol. Pg.870  ENBRIDGE 1 one question of clarification. 2 I think you made some reference to the rates 3 of return that have been filed in the United States with 4 regard to electricity distribution companies recognizing 5 the restructuring going on. 6 The question that came to my mind was: How 7 did that compare to gas rates of return that have been 8 found in the United States under the same sort of time 9 period? 10 MS ALLAN: Since we are not in Enbridge's next 11 rate case, Mr. Dominy -- 12 THE PRESIDING MEMBER: I was just wondering -- 13 MEMBER VLAHOS: I can always go out of the 14 room. 15 MS ALLAN: No, I am talking about the next 16 one, Mr. Vlahos, not the current one. 17 In general, Mr. Dominy, the statement is true 18 for gas distribution in the U.S. vis-a-vis Canada. 19 I don't know if you have been following the 20 proceeding before the British Columbia Utilities 21 Commission. There was evidence that was filed by the 22 Canadian Gas Association laying out these differences in 23 the regulatory approach in Canada and in the U.S. in the 24 last few years. 25 THE PRESIDING MEMBER: I had not meant to go 26 down that path. The path I was going down is: Was 27 there any difference between the rates of return found 28 in the U.S. for electricity as opposed to rates of || Vol. Pg.871  ENBRIDGE 1 return found in the U.S. for gas utilities? Or were 2 they perceived as having relatively the same risk and 3 therefore the rates of return that were found were 4 similar? 5 MS ALLAN: I haven't studied it to that level 6 of detail. My understanding is that they are similar. 7 It is obviously state by state. It may be that 8 individual electrics have seen higher returns than the 9 corresponding gas utility. 10 I think, in general, they are more similar 11 than they are divergent. 12 THE PRESIDING MEMBER: That is the point I was 13 trying to get at, whether one can draw from it that 14 there was any difference in risk between the two types 15 of utility within the same jurisdiction. 16 MS ALLAN: Part of the issue is that a lot of 17 the gas distribution utilities have kept their returns 18 high simply by not going in for rate cases. That is not 19 a facetious comment. It is a recognition of -- in 20 effect, they have created their own incentive envelope 21 by operating under a rate freeze for a certain period of 22 time. 23 Mr. Winter discussed that when he was here 24 for -- our targeted proposal, that is the route that a 25 number of U.S. utilities have chosen to in effect invent 26 their own PBR. 27 I think that the electrics, because there is 28 more change, have tended to come in and have been making || Vol. Pg.872  ENBRIDGE 1 these arguments around the restructuring more often than 2 the gas utilities have. 3 THE PRESIDING MEMBER: The last question I had 4 was with regard to the sequence of events in your 5 consultant's report, Navigant Consulting. I did not 6 receive this report until recently, so I can't express 7 having read it very thoroughly. But I did notice a 8 couple of sentences in there. 9 It says: 10 "In our opinion rates for the three-year 11 period for first generation PBR should be 12 frozen..." 13 For small utilities and for large utilities 14 the first year it should be frozen after having made an 15 adjustment for the rate of return." 16 I wonder whether someone could explain that to 17 me. Do they mean that there would be no escalator and 18 no productivity factor; that you just change the rates 19 and keep it fixed for the next year? 20 MS ALLAN: Could I have a reference, 21 Mr. Dominy? 22 THE PRESIDING MEMBER: Page 10 of the report 23 by Navigant Consulting Inc. 24 MS ALLAN: Yes. If you go to page 4, it is 25 laid out in a bit more detail. The reason for the 26 distinction between large and small was to move to the 27 cost allocation studies for the large utilities. 28 But for the small utilities, it would be as || Vol. Pg.873  ENBRIDGE 1 you described. It would be the one-off change, and then 2 rates would be frozen. 3 THE PRESIDING MEMBER: Does Enbridge adopt 4 that position as the position they propose? 5 MS ALLAN: There was discussion at many times 6 throughout the consultation about the advantages of a 7 rate freeze in terms of simplicity. We felt it was more 8 important to make sure there was an explicit incentive. 9 There would be an implicit incentive in what Navigant 10 has recommended, but we wanted to see an explicit 11 incentive. 12 We don't have a problem with what he is 13 recommending. It is an alternative that would 14 accomplish a lot of the goals that we are looking at. 15 We put forward our proposal because we wanted to see an 16 explicit incentive. 17 MEMBER VLAHOS: Ms Allan, just on the same 18 point, as to the treatment of this report by Navigant, 19 there are certain other recommendations in the report, 20 and you have not dealt with those. So I am not sure 21 whether you adopt the report and simply highlight some 22 of its recommendations, or you do not adopt some of the 23 other findings. 24 And I can be specific. For example, on the 25 kinds of expenses that may qualify Z-factors and the 26 proportion of those that should be -- I think it was a 27 number of 90 per cent of the types that should represent 28 certain types of costs. And also there was some || Vol. Pg.874  ENBRIDGE 1 discussion on the system based liability measures. 2 So there are things like that throughout the 3 report. Your own submission is silent on those, and I 4 am not sure how to take that. 5 MS ALLAN: Mr. Vlahos, in general we agree 6 with the consultant's recommendations, but we could 7 undertake to advise if there are recommendations that we 8 disagree with. 9 I would just like an opportunity to review 10 them. Certainly I mentioned the service quality ones. 11 We feel that it should be a smaller set. 12 MEMBER VLAHOS: That's fine. If you intend to 13 follow up with a final submission, you can do it at that 14 time. 15 MS ALLAN: Thank you. We will do that. 16 THE PRESIDING MEMBER: Anything from board 17 staff? 18 MS KWIK: No, we do not, Mr. Chair; thank you. 19 THE PRESIDING MEMBER: We would like to thank 20 you, Ms Hare, Ms Allan, Mr. Cartwright and Enbridge for 21 their presentation. We look forward to receiving any 22 final submissions. We will read it all very carefully. 23 MS ALLAN: Thank you. 24 MS HARE: Thank you. 25 MS KWIK: Mr. Chair, excuse me. Before the 26 MEA comes up, just a procedural matter. They have filed 27 an exhibit that goes along with their oral submission. 28 Would you like me to assign an exhibit number to that? || Vol. Pg.875  ENBRIDGE 1 THE PRESIDING MEMBER: If we can put it in the 2 record. I think we were just using numbers for 3 undertakings. If we could just put -- 4 MS KWIK: Exhibit 4.1. 5 THE PRESIDING MEMBER: Yes. 6 MS KWIK: Thank you. 7 EXHIBIT NO. 4.1: Document entitled MEA 8 Oral Submission - Exhibit (October 7, 9 1999) 10 THE PRESIDING MEMBER: Now the MEA. Welcome 11 Mr. Tucci. I don't know who is the lead. 12 PRESENTATION 13 MR. TUCCI: I am Maurice Tucci, a staff member 14 with the Municipal Electric Association. To my left is 15 Hal Clark, General Manager of Waterloo North Hydro and 16 Chair of the MEA's Rates and Costing Committee. 17 I hope to be very brief in my opening remarks 18 and focus on rate design issues. It's not by bad luck 19 that I am one of the last presenters. I asked to be 20 scheduled last specifically to allow me enough time to 21 gather some pricing impact information from individual 22 utilities. 23 However, my plan didn't work completely. 24 Today I can only speak in some generalities. I hope I 25 can provide additional detailed information and a 26 written submission. 27 The advantage of speaking last is that I have 28 had the benefit of hearing from the previous presenters. || Vol. Pg.876  MEA, Presentation 1 I have noticed that during the oral presentations and 2 follow-up question sessions there have been some 3 discussions on certain rate design issues which we 4 believe previously had maybe not been given enough 5 scrutiny. 6 I think some of the earlier discussions have 7 raised significant concerns, including discussions from 8 this morning's presenters. I would like to summarize 9 the rate design issues from our perspective. 10 Firstly, I would like to acknowledge that 11 Board staff have addressed some of our earlier rate 12 concerns in their opening comments at the start of the 13 oral hearing. I believe Board staff indicated that 14 utilities are encouraged to consider rate impact 15 mitigation options when the resulting increase on the 16 total bill is significant. As an example, they have 17 suggested a nexus of 10 per cent. 18 Board staff have also said consideration 19 should specifically be given to rate impacts on 20 customers within a rate class associated with changes in 21 the rate structure. Staff has suggested that the Rate 22 Handbook should make the distribution utility 23 responsibility for rate impact mitigation and that 24 utilities should carry out a rate impact assessment 25 which will be reported to the Board. 26 Staff also pointed out that the distribution 27 utilities can mitigate impacts from market based rate of 28 return, transition costs and extraordinary costs through || Vol. Pg.877  MEA, Presentation 1 a deferral account in order to spread costs with accrued 2 interest over future years. 3 We believe all these suggestions will help in 4 addressing some of our concerns. The option to defer 5 price increases is an important tool to address impacts, 6 but we believe another tool which may be needed is more 7 flexibility in rate design in order to adequately deal 8 with the impacts within a customer class caused by 9 moving to a single customer charge and a single demand 10 or energy charge. 11 We believe that most utilities will rely on 12 the approach provided in Appendix A to establish initial 13 rates rather than carry out their own cost of service 14 studies. 15 Unfortunately, only a handful of utilities 16 have to date attempted to develop initial rates based on 17 the appendix. As a result, I am concerned that the 18 simplified approach to unbundled costs has not been 19 adequately tested and there may be problems which will 20 require either more explanation or modification to the 21 approach. 22 We have contacted a few utilities that we 23 understood had attempted to use the appendix and after 24 some discussion, we found that most had made a number of 25 assumptions to complete their analysis. We don't know 26 whether their assumptions were consistent and, as a 27 result, we don't know whether the results are 28 comparable. Nevertheless, we have noticed some outcomes || Vol. Pg.878  MEA, Presentation 1 which have been generally consistent and I will get to 2 them later. 3 First I would like to point out one of the 4 problems with the method used to establish the class 5 distribution revenue requirements. The simple five 6 interim approach derives class distribution revenues by 7 separating the costs of power from existing rates for 8 each class. This approach relies on the data provided, 9 the load data provided in Appendix A. 10 The problem with this approach is that the 11 revenues could be inappropriately assigned to classes 12 because the load data provided is very specific to the 13 mix of customers of a utility used, for example, in 14 Appendix A. 15 We know that utilities' mix of customers vary 16 considerably. A utility with more or less electric 17 space heating or air conditioning load will have a very 18 different load pattern for each of its classes. We 19 recognize that this problem cannot be rectified without 20 obtaining more generic load data. Utilities will have 21 the option to use better data, but we suggest that there 22 may be other approaches to determine class revenues 23 which should be reviewed. 24 With respect to the incremental distribution 25 costs, or IDC, of 6.2 mills per kilowatt hour, we note 26 that the Board staff have proposed this is a default 27 value in absence of an alternative. We agree that it 28 may be possible to develop an updated IDC, but we have || Vol. Pg.879  MEA, Presentation 1 also suggested that the existing value could be improved 2 through some modifications. 3 We note that subtracting the utility's own 4 historical loss rate rather than the default value of 5 2.5 mills per kilowatt hour causes some troublesome 6 outcomes. The default value is based on an average 7 utility loss of 3.5 per cent. 8 If a utility with higher than average losses 9 uses their own loss rate rather than the default rate, 10 the remaining IDC, or wires only IDC, could be lower 11 than a default value of 3.66 mills per kilowatt hour. 12 This would result in less revenue being collected 13 through the demand charge and a correspondingly higher 14 customer charge. 15 If, on the other hand, a utility had low 16 losses, the remaining wires on the IDC would be 17 relatively higher than the default with a 18 correspondingly low customer charge. For the low loss 19 utility with a high demand charge, there are higher 20 impacts on larger customers. 21 It is not clear to us whether making the IDC 22 dependent on utility specific losses is appropriate. We 23 believe that further analysis should be carried out to 24 determine whether the default only IDC value of 3.66 25 should be used in order to avoid the sensitivity to a 26 utility's own losses. 27 With respect to the default value of 3.66, we 28 have received some further concerns. A utility's || Vol. Pg.880  MEA, Presentation 1 incremental demand costs are driven by demands. As 2 such, incremental distribution costs should be recovered 3 through demand charges. 4 The wires only IDC of 3.66 mills per kilowatt 5 hour has an implied load factor of an average utility. 6 In Appendix A the kilowatt hour based IDC is converted 7 into a kilowatt charge for each class. We believe 8 consideration should be given to establishing a default 9 wires only IDC based on a kilowatt value. In this way, 10 the kilowatt charge would not be dependent on the class 11 load factor. 12 We note that with a default wires only IDC 13 converted into a kilowatt charge, the revenues collected 14 from this charge would depend on a mix of customers 15 within the class. We have found that because a 16 residential class is relatively homogeneous, 17 particularly in comparison to the general service class, 18 generally consistent customer charges are obtained from 19 different utilities. 20 We have so far observed residential charges 21 which range from $12 to $24, without including the 22 market based return under any estimate of transition 23 costs. The average appears around 15 and I hope I can 24 update these figures for the written submission. 25 For the general service class where utilities 26 often have a very different mix of customers, some with 27 very large customers and some with none, the resulting 28 customer charge appears to vary widely. || Vol. Pg.881  MEA, Presentation 1 The general service customer charge may range 2 from $50 to $100. As I said earlier, I have not had an 3 opportunity to review whether the approaches were 4 consistent, but I'm concerned that one of the reasons 5 for the wide differences may be due to the mix of 6 customers. 7 The problem we see with the wide range is that 8 a small general service customer paying a $100 customer 9 charge will wonder whether costs are tracked properly 10 when he finds customers in neighbouring utilities paying 11 considerably less. We would also ask why he is paying 12 more than a residential customer in the same utility. 13 Historically, we have designed rates such that 14 small general service customers and residential 15 customers have rates that are comparable. We believe 16 some co-ordination between these customer groups should 17 continue. 18 As a result, small general service customers 19 probably should be treated as a separate subclass with 20 some method to have a smooth transition to the standard 21 general service rate. We suggest that subdividing the 22 general service class would assist in providing some 23 consistency in results between utilities so that the 24 customer charge would not be so dependent on customer 25 mix. 26 It would appear that the single customer 27 charge in a single energy or converted equivalent demand 28 charge for the entire general service class does not || Vol. Pg.882  MEA, Presentation 1 track costs appropriately and is causing the 2 inconsistent results. 3 We are not suggesting that the customer charge 4 should be lower for all general service customers. We 5 believe there is some theoretical support for having 6 higher customer charges for larger customers. Larger 7 customers have higher metering costs and it can be 8 argued that larger customers should also bear a higher 9 proportion of the utility's fixed distribution costs. 10 We have observed that default IDC appears to 11 be collecting more revenue from the largest general 12 service customers than under the previous rate 13 structure. More review is required to determine whether 14 this is appropriate. 15 We note that with the loss of the large user 16 diversity adjustment rates to larger customers will 17 increase, but we need to review whether a different IDC 18 should be used for larger users. 19 Another significant rate design issue is the 20 methodology for recovering the market based rate of 21 return and the associated taxes. As some have noted 22 previously, the market based rate of return and taxes 23 are entirely collected through the customer charge, that 24 the market based return and taxes are allocated to 25 classes based on total revenues. 26 As a result, we have observed that a 27 market-based return and associate taxes can double or 28 triple the customer charge depending on circumstances. || Vol. Pg.883  MEA, Presentation 1 We found one analysis showing the residential customer 2 moving from $15 to $30 and a general service rate charge 3 moving from $75 to $175. 4 Should the customer charge not track costs 5 appropriately within the class, the recovery of the 6 market-based rate of return compounds the problem. This 7 also highlights the problem of using a single customer 8 charge for the entire class. Using a single charge 9 results in having a small customer pay the exact same 10 contribution to return as a larger customer even though 11 having included the large customer in the class resulted 12 in more revenue being allocated to the class. 13 The MEA believes that more work is required to 14 make Appendix A an appropriate method for establishing 15 initial rates. We hope this work is completed before 16 the initial filing of rates and we would suggest that 17 Board staff issue a tentative spreadsheet program for an 18 initial rate soon. 19 With a single model we would eliminate the 20 inconsistencies and approaches to interpreting 21 Appendix A and thus would have better information on the 22 impacts of Appendix A. This would also allow utilities 23 to determine early in the process whether there are any 24 practical problems with using the Appendix A methodology 25 for their utility. We believe more work is required to 26 develop an improved methodology for establishing initial 27 rates. What we don't know is whether we have enough 28 time. || Vol. Pg.884  MEA, Presentation 1 In closing, I would like to say we concur with 2 the majority of the other speakers who have noted the 3 considerable efforts made by the Board staff and 4 consultants in formulating the draft Rate Handbook. We 5 believe the OEB staff had benefitted from the input 6 received from the four PBR task forces, utilities and 7 various stakeholders, and we believe the discussions 8 with stakeholders to the technical conference and the 9 oral hearing has provided all of us with a better 10 understanding of the issues and tradeoffs you will 11 consider as you finalize the Rate Handbook. 12 Before I finish my remarks, I would like to 13 explain the exhibit that we have provided on rate 14 impacts. 15 THE PRESIDING MEMBER: Thank you. 16 MR. TUCCI: Firstly, I will point out that we 17 made some simplifying assumptions. The cost of power is 18 the existing value so it doesn't represent the impacts 19 that could be caused by breaking up the value into a 20 charge for IMO, transmission, commodity or CTC. 21 For the residential class in this example the 22 customer charge is around $13 and it appears to collect 23 approximately the same amount of distribution that we 24 collect through the first block. 25 There is a little note at the bottom of that, 26 the first chart, that says the difference between the 27 12.09 cents and the 7.1 cents, that's the first block 28 and the second block, that difference of around 5 cents || Vol. Pg.885  MEA, Presentation 1 is multiplied by the 250 kilowatt hours gives you around 2 $12.50. So it is roughly tracking what we collect right 3 now in the first block. 4 So as an unbundled rate it works for the 5 residential class to some degree, but when you add in 6 the market-based returns you can see that the rate 7 impacts mostly affect the smallest customers. 8 With respect to the general service class, we 9 found that it appears there is a $53 customer charge and 10 generally the smallest customers, without a return, are 11 paying considerably more and the largest customers are 12 paying less than they did before. Adding the return in 13 this example you can see the smallest customers bear the 14 biggest brunt of the market-based return and the largest 15 customers are actually paying still less than they did 16 before. 17 Now, this is just this example. If you look 18 at other examples you might find slightly different 19 results, but generally this sort of shows the trends 20 that come out from using Appendix A. 21 We can take questions now. 22 THE PRESIDING MEMBER: Thank you, Mr. Tucci. 23 Basically, what you have told us is that you 24 have some reservations and some concerns about the 25 methodology which is used and it needs to be amended in 26 order to mitigate the effects that the change in rate 27 structure would have on customers. 28 MR. TUCCI: Yes, that's my focus. It wasn't || Vol. Pg.886  MEA 1 just adding the market-based return. We have ways of 2 mitigating that. But if we moved immediately to this 3 new rate structure we would have immediate impacts that, 4 unless we had some flexibility, we wouldn't be able to 5 control. 6 THE PRESIDING MEMBER: As part of your 7 submission, final submission, will you be in fact making 8 a suggestion or a recommendation as to the proposal that 9 would help offset those concerns? I suggest "This is 10 the way it should be done" or "Here is a factor for the 11 IDC" or a number for the IDC which is probably closer to 12 what you perceive as being the right number. 13 MR. TUCCI: I think the question for us is 14 whether we -- when you start trying to design rates 15 there are a number of different factors that need to be 16 considered. What is not clear to us is where would we 17 be putting our emphasis on. We have a lot of 18 conflicting goals here and I think we can make a 19 proposal but we would still be second-guessing what you 20 might be looking for. 21 I have talked to Board staff about this and 22 they have often said, "Make your pitch and we will 23 consider it." The problem with us is that we are not 24 sure what the ultimate goal is that we are trying to 25 achieve. 26 There has been a lot of discussion on having a 27 demand charge that sends the right price signal. If we 28 are concerned about the right price signal that would || Vol. Pg.887  MEA 1 lead us to trying to track the incremental demand costs 2 as well as we can. Then we are stuck with trying to 3 determine how do we collect the rest of our revenue and 4 how do we allocate that to our customers. 5 There are questions about equity and fairness 6 versus efficiency, and that's the problem that we have 7 is that we can make some judgment calls and make a 8 proposal, but we are not sure we can second guess all 9 the goals that we are trying to meet for all the 10 utilities. 11 There are a lot of different factors that we 12 are trying to meet, and that is one of the problems, 13 like simplicity in regulating the rate caps. If we had 14 suggested -- I mean, one of the ideas that we could 15 pursue would be to allow utilities to have a different 16 demand charge, but I'm not sure how much latitude we 17 would have in terms of changing the demand charge and 18 whether there would be concern from the regulator about 19 having too much control over varying all the factors: 20 raising the demand charge or lowering the customer 21 charge. 22 THE PRESIDING MEMBER: Mr. Clark. 23 MR. CLARK: I just want to comment that one of 24 the discrepancies we see is that there is quite a 25 difference in what a residential customer would pay 26 versus a general service customer. If you look at, say, 27 1,000 kilowatt hours a month a residential customer 28 would pay about $83 where a general service customer || Vol. Pg.888  MEA 1 would pay $120. 2 Like, one of the proposals that I might put 3 forward would be that you would have the same customer 4 service charge for all single phase customers whether 5 they are residential or commercial, and you would have 6 another customer service charge if it is a three-phase 7 customer, which would be basically your larger general 8 service customers. 9 Now, that would solve the problem about 10 different rates for customers that have the same 11 consumption but are in different classes. It would also 12 represent a signal that -- like, a three-phase customer 13 requires more facilities to supply it so they would pay 14 more. It would solve that problem. But I would want to 15 explore that because we haven't done any 16 number crunching on it to determine what other impacts 17 might be. But it would be one solution that we might 18 put forward as an alternative. 19 MR. TUCCI: It would address the problems at 20 the low end to some degree. Even if we did subdivide 21 the small general service customers out, there would 22 still be tracking problems within the rest of the 23 general service class. 24 So I think Paul Ferguson was suggesting this 25 morning some approach that would have a higher customer 26 charge for larger customers and I asked him to provide 27 me a copy also. We will be reviewing that and seeing if 28 we could use any ideas from there. || Vol. Pg.889  MEA 1 All we can do is put forward some proposals 2 and ideas. We wouldn't be able to actually -- I mean, I 3 don't think we have enough time to actually work out 4 exactly a methodology with all the numbers and 5 specifics. We can only suggest some things in time for 6 the written submission. 7 THE PRESIDING MEMBER: Well, you could 8 certainly suggest a process that might be followed to 9 resolve these difficulties if they exist, whether it is 10 consultation or some mechanism. 11 I know that what has been put in, as I 12 understand it from Board staff, is a mechanism that 13 utilities may adopt because they all face the issue of 14 How do we unbundle the rate? That is really the issue. 15 Now, what would be your view if unbundling 16 just meant taking out of the existing rates the cost of 17 power from every step of the rate? 18 MR. TUCCI: We haven't really spent enough 19 time trying to figure out whether that would work. It 20 sounds like an easy way to make the transition, but I 21 haven't tested the idea with other utilities to see if 22 they could get that to work. 23 But I guess the problem then is, when do we 24 start moving toward more customer charges? I guess that 25 is the problem. Would that rate be frozen for the whole 26 three years and then we would implement customer 27 charges. 28 I mean, there are lots of things to consider || Vol. Pg.890  MEA 1 here and we are not sure yet whether the utilities are 2 willing to move away completely from a customer charge, 3 given that we are moving to a PBR scheme and the more we 4 rely on kilowatt hour charges the more at risk we are in 5 terms of revenues. 6 So we haven't quite figured out if it 7 would work. 8 I know some utilities feel that they could 9 live with that variance, but maybe those aren't the ones 10 that are aiming towards a market-based return on day 11 one. So I'm not sure. 12 THE PRESIDING MEMBER: I'm incorrect in the 13 sense that I said just take the cost of power out. You 14 also have to add in, if the utility wishes to go to it, 15 the market-based return as well. 16 MR. TUCCI: Yes. I'm saying something that 17 would be more reliant on a kilowatt hour charge that is 18 blocked the way the rates are blocked right now, that 19 would really reduce the rate impacts. 20 The question then is just whether we are just 21 delaying the inevitable. What first step should we take 22 in year one and do we -- I mean, it could be a 23 reasonable way of doing things given that we have to 24 deal with the rate impact caused by adding in the 25 market-based rate of return. 26 We are trying to achieve some of the same 27 results without actually using the kilowatt hour charge. 28 That is the problem. We have been trying to figure out || Vol. Pg.891  MEA 1 how to impact the customers fairly, but we haven't 2 figured out how to make it work with just a kilowatt or 3 a demand charge yet. 4 THE PRESIDING MEMBER: All right. 5 Ms Kwik is looking at me. I'm sure she has 6 questions. 7 MS KWIK: Do you want me to go ahead of 8 Mr. Vlahos and Dr. Zerker? 9 THE PRESIDING MEMBER: Go ahead, Ms Kwik. 10 MS KWIK: Okay. Thank you, Mr. Chair. 11 I actually do appreciate all the suggestions 12 that you have in your submission. It is unfortunate 13 that we didn't come up with them when we were working 14 together on the rates task force, but I suppose late is 15 better than never. I think sort of keeping in mind some 16 of these suggestions will, in the end, provide for a 17 better model. 18 But I do want to ask you some questions on the 19 specifics. 20 You say that you recognize there is a problem 21 that cannot be rectified without obtaining generic load 22 data. Then you go on to say that: 23 "We suggest that there may be better 24 approaches to determine class..." 25 (As read) 26 I assume distribution revenues? 27 MR. TUCCI: Yes. 28 MS KWIK: "...which should be reviewed." || Vol. Pg.892  MEA 1 (As read) 2 Can you share with me what these suggestions 3 might be? 4 MR. TUCCI: Well, we have heard some 5 suggestions to use, I guess, the generic data to 6 actually -- 7 Maybe right now I shouldn't even try to 8 explain it because it is a bit complicated and I'm not 9 sure I understood it completely when the utility person 10 told me how they are doing it. 11 But there is a different approach that doesn't 12 rely so much on these factors and it sort of says you 13 look at the total amounts of load from each of your 14 classes, allocate some kind of generic load profile to 15 it, and rather than worrying about subtracting the cost 16 of power and having -- 17 I don't want to start second guessing exactly 18 what he said because I wasn't sure exactly myself. I 19 just wanted to flag the issue that there may be 20 different ways. 21 I will mention that it was Don Thorn that was 22 suggesting a different approach and he has spent some 23 time thinking about it. Usually when Don has an idea 24 it's worth looking into. So I haven't had a chance to 25 actually ask him more specifics on that. 26 MS KWIK: Is it something you might be able to 27 include in your written submission? 28 MR. TUCCI: Yes, I will pursue it with Don to || Vol. Pg.893  MEA 1 see whether he can explain it a little bit better to me. 2 MS KWIK: Thank you. 3 MR. CLARK: My understanding of what he was 4 suggesting is that you start with the distribution 5 costs, which you can take right off of our financial 6 records, and somehow allocate those costs based on the 7 kilowatt hour consumption by the various customer 8 classes so that you -- 9 That may not end up being class revenue 10 neutral. I think that is the problem. So there would 11 have to be some form of adjustment in there to make sure 12 that was right or if that is in fact what you wanted. 13 But rather than backing out the cost of power 14 out of the revenue you start from the distribution costs 15 and build it up that way. 16 MS KWIK: Okay, I see. I understand. 17 Thank you. 18 The next point is on the use of the default 19 value for the system losses when you are trying to come 20 up with a utility-specific incremental distribution 21 cost. 22 The suggestion is that if the utilities use 23 their own system loss to come up with their IDC they may 24 run into problems because their IDC value would be quite 25 low. I assume it would probably would be 26 unrealistically low? 27 MR. TUCCI: Well, it depends. I have seen 28 some analysis that shows it does vary a lot, but I can't || Vol. Pg.894  MEA 1 confirm it yet. 2 I think it requires -- it is depending on what 3 assumptions people were using I think is the problem. 4 MS KWIK: Would it help, would it make a 5 difference if the default system loss was used as an 6 upper level of loss? 7 MR. CLARK: It may help if the loss part were 8 actually pulled right out and set aside and you had the 9 IDC as a separate number. 10 Like our utility has losses in the range of 11 3.5 to 4 per cent. I know one utility that has losses 12 in the range of 1 per cent. When you pull out those 13 numbers you get what is left over out of the 0062. You 14 get quite a variance in the number. 15 You may be better off to pick something like 16 .005 for the IDC and leave the loss to float through the 17 cost of power as an alternative. 18 The question is: Where did the 0062 come from 19 in the first place? My understanding is that that is a 20 number that came out of a range which may vary from, 21 well, something that is this wide and they picked a 22 number in the middle. 23 I think each and every one of us in this room 24 would probably come up with a different number as to 25 what that incremental distribution charge should be. 26 MS KWIK: It seems that we have been left with 27 an awful lot of the average of the range in a lot of the 28 setting of the initial rates. || Vol. Pg.895  MEA 1 MR. CLARK: Yes. 2 I would personally assign a lot higher number 3 I think to the incremental distribution charge from what 4 this number is. That is my impression, that it should 5 be higher. 6 MS KWIK: That is a gut feel -- 7 MR. CLARK: Yes. 8 MS KWIK: -- or do you have a methodology? 9 MR. CLARK: I have a methodology. Like I 10 probably feel that there are a number of ways you can do 11 this. 12 But if you go back to kind of the minimum 13 system, you don't need much of a minimum system to light 14 100 watt light bulb in all of the customers' premises. 15 If you assume that everything beyond that is kind of an 16 incremental cost, then that gives you quite a bit of 17 different number than what you have here. 18 But it all depends on the philosophy and how 19 you want to say what goes into the service charge and 20 what goes into the variable portion. 21 MR. TUCCI: You heard it this morning, I 22 guess, from the Cottagers Association, where they were 23 saying they were proposing that maybe the customer 24 charge should only have meter reading and some billing 25 costs and that's it and all the demand costs go into the 26 demand charge. 27 We would still like to have demand costs, you 28 know, some fixed component in there. || Vol. Pg.896  MEA 1 I guess the question is: What is the overall 2 philosophy? Do we have a demand charge that is strictly 3 just incremental, that doesn't really try to track costs 4 as well as we did before, historical load, or do we 5 lower the demand charge and have then customer charges 6 that sort of reflect historical consumption? 7 So a larger customer would pay more through a 8 customer charge. 9 But then that leads to other problems in terms 10 of having steps in the rates, where a customer charge 11 for one customer is $100 and the next customer, a little 12 bit higher, is $200. You have these continuities in the 13 rate structures. 14 That is why the customer charge approach has 15 problems of its own and why I was suggesting that if we 16 had stuck to kilowatt hour charges and a higher kilowatt 17 hour charge, we would track costs a little bit better. 18 MS KWIK: Thank you. The next question I had 19 is on using an IDC based on a KW value. Could you 20 explain to me exactly how that would be approached. 21 MR. TUCCI: I think what you would do is 22 convert that value for -- I think there was an implied 23 load factor in that IDC value. I haven't been able to 24 track it down. I noticed the Green Energy Coalition 25 witness said it was a 60 per cent load factor. 26 If you can verify that, you would take the 27 default IDC and try to convert that into a kilowatt 28 charge so that all the utilities would use the same || Vol. Pg.897  MEA 1 kilowatt value. It wouldn't vary according to what the 2 utility -- it is not clear to me why the IDC value 3 should vary according to load factors. 4 I didn't understand the concept behind that. 5 I know we are sort of fine tuning a number that is not 6 that accurate to begin with. 7 MS KWIK: Accepted. 8 MR. TUCCI: I am trying to reduce some of the 9 variability between utilities. 10 If you did that, if that is the goal, the 11 demand charge would be exactly the same for all the 12 utilities. As it is now, it wouldn't be. 13 MS KWIK: I understand; thank you. 14 I think your suggestion of applying the 15 incremental rate of return to bring you to market-based 16 rate of return both to the service charge as well as to 17 the throughput charge is a good idea, and I wish we had 18 thought of it earlier. 19 Is it then a matter of first establishing the 20 revenue requirement for the fixed side and for the 21 throughput and then adjusting both of those levels for 22 the market-based rate of return and the transition cost? 23 MR. TUCCI: Again, I think it depends on what 24 you are trying to do. If you put in a market-based 25 return, its fair share into the demand charge, you would 26 be tracking costs better. The problem is we don't 27 understand what the theory is behind sending the right 28 price signal. || Vol. Pg.898  MEA 1 If that demand charge now includes a return 2 and it is a bigger price, are we still sending the right 3 price signal? 4 I guess it requires an economist to tell me 5 whether that is correct. 6 MS KWIK: So this is a good idea, but what you 7 are saying is that you still need to think about it. 8 MR. TUCCI: Yes. 9 MS KWIK: Thank you. 10 MR. CLARK: I would argue that the IDC should 11 have some of the return built into it. Certainly larger 12 use customers use a lot more of the distribution system. 13 It is the distribution system that is going to create 14 the return on equity, and it should therefore be the 15 larger users that contribute to that. 16 I don't know what the formula is. 17 MR. TUCCI: I was saying that they should pay 18 for it. But the question is -- it should be allocated 19 to the larger customers, but should they actually see 20 that in the demand charge? That is my concern. 21 MS KWIK: Thank you. 22 The other issue that you did bring up was the 23 use of the IDC for large use customers and that the IDC 24 may not be appropriate for the large use customers. I 25 am assuming that the IDC for large use customers would 26 probably be lower since some of them come right off the 27 transmission. 28 MR. TUCCI: Yes. || Vol. Pg.899  MEA 1 MS KWIK: Would an alternative to the method 2 provided in Appendix A be to use the ratio of the 3 revenue from the service charge and the revenue from the 4 throughput charge and apply that ratio to the large use 5 rates? 6 MR. TUCCI: Say it again? I don't understand. 7 MS KWIK: I see the problem here is because 8 the IDC does not apply to the large users. 9 MR. TUCCI: Yes. It doesn't. 10 MS KWIK: So as a way of breaking out the 11 rates for them in terms of the service charge and a 12 throughput charge, would the approach maybe be better to 13 go to the general service class and take the ratio of 14 revenue from the general service monthly service charge 15 and the revenue from their throughput charge and use 16 that ratio? 17 Say that ratio came to 70 per cent for the 18 monthly service charge and 30 per cent from throughput. 19 We could then apply that ratio to the large use. 20 Would that be a good alternative? 21 MR. CLARK: The problem with using some form 22 of an average number from the general service class for 23 the larger users is that they could have quite a bit 24 different load shapes, particularly when you are using 25 the average of the general service. You may end up with 26 a comparison which doesn't match up very well. 27 I would want to look at the numbers, but there 28 is a danger there that you are comparing one type of || Vol. Pg.900  MEA 1 customer, the average of a group of customers, which may 2 be completely different than the large users. 3 MS KWIK: I guess this is comparing to your 4 concern that using the IDC of .006 is totally 5 inappropriate. 6 MR. TUCCI: Yes. I think it's -- 7 MS KWIK: It's the one that is the lesser of 8 the two evils. 9 MR. TUCCI: I understand what she is saying. 10 She is saying instead of having .66, if you try to work 11 it out so they did have a customer charge because right 12 now you are getting a negative number, I think, for the 13 customer charge. 14 MS KWIK: Possibly, yes. 15 MR. TUCCI: So to have them have some kind of 16 customer charge and then -- 17 MR. CLARK: Start with the customer charge, 18 the general service use and then adjust the IDC. 19 MR. TUCCI: Yes. 20 MR. CLARK: At least there would be 21 co-ordination there between kind of one group and the 22 other. 23 MS KWIK: Yes. 24 THE PRESIDING MEMBER: Ms Kwik, are we going 25 to get anywhere in discussing in detail, or would there 26 be something better to be discussed? 27 MS KWIK: I did want to state that we are 28 going to be testing the model that we develop once the || Vol. Pg.901  MEA 1 Board has made a decision on this part of the proposal, 2 and that we would like to very much have utilities test 3 the model; whether you would be willing to work with us 4 in testing the model. 5 MR. TUCCI: Yes. That is what we were 6 seeking. We wanted to make sure that it was tested and 7 that if there were problems, we could fix them. 8 That's the only reason I was here, just to 9 make sure we had the flexibility to make corrections to 10 the appendix after we had an opportunity to test it. 11 MS KWIK: Thank you. That is all, Mr. Chair. 12 THE PRESIDING MEMBER: Before I ask my 13 colleagues whether they have any questions, there is one 14 question that I want to ask. 15 This morning, as part of their submission, 16 Mr. Roman on behalf of Halton Hills and the City of 17 Peterborough made reference to comparative reports 18 published by the MEA with regard to performance measures 19 of the various utilities. 20 I wonder whether you could give me some 21 indication of what performance measures are reported, 22 and are these publicly available reports. 23 MR. TUCCI: I don't recall all the numbers. I 24 didn't bring a copy with me. They do have reliability 25 measures in the reports, and they have, I think -- they 26 were talking about controllable costs. 27 MR. CLARK: I think, typically, there is 28 probably about 30 different indicators, like || Vol. Pg.902  MEA 1 controllable costs, the reliability numbers, meter 2 reading costs, billing costs on a per customer basis. 3 There are a number of them. 4 I believe they are shown by individual 5 utilities. So whether or not they are public -- 6 MR. TUCCI: I know that there is a 7 confidential agreement there. I think the individual 8 utilities that participate get the data, and other 9 utilities that don't participate just get the generic 10 average numbers. They don't actually get the breakdown. 11 So there are some average numbers that are out 12 there. But you wouldn't be able -- it is not useful for 13 identifying individual utilities. You just know that 14 there is a range, and these are the kinds of numbers for 15 large, medium and small. 16 I think this morning they were talking about 17 the benefits of -- you know, individual managers know 18 how well they are doing compared to other utilities. 19 They get the benefit of seeing this number. I actually 20 haven't seen the number. It is only given to utilities 21 that participate. 22 THE PRESIDING MEMBER: In the context of 23 performance measures and some mechanism to provide an 24 incentive, what is your position with regard to the 25 Board setting up performance measures, collecting the 26 performance data and then publishing it and making it 27 available so that people, on a peer pressure basis, can 28 try and ensure that their utility is in the top || Vol. Pg.903  MEA 1 quartile, or mix of top quartile performance measures; 2 that they appear at the top and not at the bottom, as a 3 mechanism to drive performance? 4 MR. CLARK: I'm kind of personally in favour 5 of that because that's kind of what we do now. Like we 6 do an awful lot of comparisons from kind of one utility 7 to the next about what our rates are, what our costs 8 are. We use that at the moment to see whether or not we 9 are in line or we need to make some adjustments. 10 So doing it in the future, I can't 11 see -- well, that's to me kind of a thing that would 12 drive utilities to be more efficient. 13 THE PRESIDING MEMBER: I was extending it a 14 little bit. I didn't mean sharing it among utility 15 managers. I meant making it publicly available so that 16 customers know some sort of measure of the quality of 17 service they are getting from their utility and, 18 therefore, you get another set of pressures on the 19 utility managers which is mainly customer pressure. 20 MR. TUCCI: I don't have a position. We 21 didn't do anything like that because we couldn't get the 22 data without them volunteering. It's a cue in a 23 different position. 24 THE PRESIDING MEMBER: Dr. Zerker. 25 MEMBER ZERKER: Just on the same issue. Is 26 this comparative study that you do useful for a 27 productivity analysis? 28 MR. TUCCI: The short answer is probably no. || Vol. Pg.904  MEA 1 I think what people were suggesting was if you look at 2 the numbers, you get a sense of the different 3 performances between utilities, but it's not enough 4 information to actually be absolutely confident that you 5 could identify. 6 I think a lot of it has to do with -- I think 7 utilities feel they know who is better than others 8 because they might actually be familiar with a utility's 9 operation, they have seen it. They know how they 10 operate. They hear stories. With that information plus 11 the numbers, then they start feeling maybe they know 12 which ones are less productive than others. 13 I think if you just looked at the data, I'm 14 not sure you could do it with confidence that if there's 15 a low performer in the data that you would be absolutely 16 sure it's entirely due to managerial circumstances. 17 There are other things that do drive costs. We don't 18 measure those things in our data. 19 MR. CLARK: I guess the one thing I look at at 20 the moment is really what the final rates are that a 21 utility charges. Like controllable costs per customer 22 may not be a very good indicator because you may have 23 low capital costs but high controllables. Your 24 maintenance costs may be high, but that may be offset 25 with low capital costs. 26 You have to put it all in perspective, but 27 when everything all boils down, it's what you eventually 28 end up charging the customer. At the moment, typically, || Vol. Pg.905  MEA 1 if utilities have lower rates over the long term and the 2 reliabilities are consistent or better than their 3 neighbours, then that's to me an indication of better 4 productivity. 5 There may be other factors that creep into 6 this. It may give you a feel for productivity, but I 7 don't think any one of them is a definitive indicator. 8 MR. TUCCI: You pointed out it's your 9 neighbour. If you have a neighbouring utility that is 10 similarly situated and their costs are higher, you would 11 start suspecting maybe there's a difference in 12 productivity. 13 It's when you look at all the data and you can 14 see trends, utilities in certain areas or with less 15 density have higher overall costs. You would have to 16 factor those kinds of things. Age of plant is a big 17 determinant. There's a list of issues. 18 Individual utilities might know what their 19 neighbours are doing, but it would be difficult to 20 gather all that information. A lot of it's just sort of 21 based on observations. It's not something you can 22 quantify necessarily. 23 MEMBER ZERKER: We have heard some people who 24 are very concerned about the productivity factor and the 25 way it is to be calculated and so there was some talk 26 about an alternative method by using comparative series. 27 You don't think -- 28 MR. TUCCI: It would require a lot of work and || Vol. Pg.906  MEA 1 analysis to get it to the point where people would 2 support it. I think that's the problem. 3 MEMBER ZERKER: It wouldn't be a good 4 supplement to an understanding of that factor. 5 MR. TUCCI: It might. Any information helps. 6 MEMBER ZERKER: More or less what I'm asking 7 is would that approach be a good supplement? I'm not 8 trying to pin you down and say I want your series and we 9 will use it, but you know, whether or not that approach 10 of developing, we are now looking for data and we are 11 looking for information. I'm wondering whether you get 12 a bunch of variables that MEUs can tell us are important 13 variables and then you start tracking that in a 14 comparative way. Would that be useful? 15 MR. CLARK: I would say it would be. I think 16 it was my kind of understanding that that was the 17 direction we were heading, that we needed time to build 18 up some of these databanks. Once these databanks on 19 these variables are available, they will become the 20 driving forces or maybe will be more of the driving 21 forces towards productivity. 22 MEMBER ZERKER: Right. 23 MR. CLARK: So as a supplement, yes, I would 24 agree. 25 MEMBER ZERKER: Yes. It's sort of the ground 26 rules, you know, or the background. 27 MR. CLARK: Yes. 28 MEMBER ZERKER: Mr. Tucci, these are the || Vol. Pg.907  MEA 1 outcomes from using Appendix A. 2 MR. TUCCI: Yes. These are for our utility 3 and they are our effort to generate numbers that would 4 apply. They were based on the 1998 costs and revenues 5 that we had and then if we were to apply a market based 6 of return in 1998. 7 MEMBER ZERKER: Right. 8 MR. TUCCI: And our understanding of how 9 Appendix A was to work. 10 MEMBER ZERKER: We saw some calculations from 11 ECMI. 12 MR. TUCCI: Yes. 13 MEMBER ZERKER: Although they are different, 14 there's one -- well, there is some similarities. The 15 similarity that is concerning is the leaps in the 16 system. Are we looking for some kind of smoothness? Is 17 that one of the objectives so that there is some kind 18 of -- 19 MR. TUCCI: Co-ordination. 20 MEMBER ZERKER: Yes, so that there is a smooth 21 rate charge, overall rate charge, however we get to it 22 for people who use, say, 2,000 and then when we are 23 going up to 2,500 there isn't some great leap forward. 24 MR. TUCCI: Yes. 25 MEMBER ZERKER: Is that what we are looking 26 for? I'm trying to figure out from what you have been 27 talking about, and I am certainly no expert in this 28 area, but I am trying to figure out what are the || Vol. Pg.908  MEA 1 criteria that we are looking for in designing a rate 2 design? 3 MR. CLARK: Well, one of the things that I 4 have always looked for is that customers that use kind 5 of the same amount of power should pay approximately the 6 same rate. 7 MEMBER ZERKER: Okay. 8 MR. CLARK: You don't want a big step. You 9 could have minor variances because maybe the meters are 10 different or whatever, but you shouldn't have huge big 11 differences. 12 The other one is as a customer moves up in 13 load size, there should be fairly close co-ordination so 14 you don't have huge big steps that when he goes from 100 15 kilowatts to 101 kilowatts, all of a sudden he finds out 16 he is paying another $100 a month more just because he 17 has increased the load by one kilowatt. 18 MEMBER ZERKER: That's what I mean by 19 smoothness. 20 MR. CLARK: Yes. You need that kind of 21 smoothing and co-ordination as you step through this. 22 Otherwise you will end up arguing with the customer 23 about -- well, when he goes over to the next size and 24 you send him out his new bill which may have an 25 increase, that's when you will end up with trouble, 26 wanting an explanation why. 27 MEMBER ZERKER: And aside from this complaint, 28 from your point of view as a utility manager, you don't || Vol. Pg.909  MEA 1 want to have unfairness built into the system. 2 MR. CLARK: That's right. At the moment I 3 would have a hard time explaining that to him as to why 4 that would be the case. 5 MEMBER ZERKER: Could you just take me through 6 this a bit. How would you get to those objectives 7 with -- 8 MR. CLARK: Well, I think -- 9 MEMBER ZERKER: -- charge and demand charge. 10 How do you see it as the best way. Never mind whether 11 or not what the design is in the handbook. Just in 12 principle, how would be the best way to get to that? 13 MR. CLARK: Well, I think the customer charge 14 for the residential and the small general service have 15 to be somewhere in the same ball park, that $13, $15 16 level, whatever it is. 17 MEMBER ZERKER: Okay. 18 MR. CLARK: So you have to get the service 19 charge down. 20 As you move up, you typically won't have a 21 residential customer that uses, say, over 50 kilowatts 22 of power. You might find some huge mansion some place. 23 But your average residential customer uses 1,000, 24 1,500 kilowatt hours a month, something like that. So 25 at that level, the general service consumers that 26 consume that amount should pay approximately the same 27 and they probably should have about the same customer 28 charge. || Vol. Pg.910  MEA 1 As you move up in the general service you may 2 want to block the service charge somehow. I'm not sure 3 how you do it. You either block the service charge or 4 you block the variable part so that there is a smooth 5 transition from one to the next. That is the part 6 that -- while at the moment there is blocking in the 7 rate structure, under this design there really isn't. 8 I have some ideas, but I would want to explore 9 them more. 10 One was to charge the same rate for single 11 phase versus three phase, because there you would have 12 the small general service customer paying the same as a 13 residential customer where you have the larger general 14 service customer which is taking three-phase power 15 paying more while he has more service. He has three 16 transformers instead of one and three conductors on the 17 line coming in, and it would make sense that he pay 18 more. 19 That is one way to do it. But there again you 20 would have to have some form of co-ordination to make 21 sure that you didn't have big steps in the amount that 22 the customers paid. 23 MEMBER ZERKER: I am not sure I understood 24 this. 25 For a large customer, can the IDC be zero or 26 close to it? 27 MR. CLARK: Philosophically, I would say it 28 should be maybe small. I don't think it should ever be || Vol. Pg.911  MEA 1 zero. 2 MEMBER ZERKER: No. But close to it? 3 MR. CLARK: It could be. 4 For our large industrial customers at the 5 moment the variable portion in the bill exclusive of the 6 cost of power is really quite small. It is down in the 7 3 per cent range, so it is quite small. I don't think 8 it ever should go to zero. It may be small, but I don't 9 think it should go to zero because the larger -- if you 10 have large-use customers and one is using 20 megawatts 11 of power and the other one is using 10, there are more 12 facilities involved, and you should be able to recover 13 those, the variable increase in the distribution system 14 because of that. 15 MEMBER ZERKER: Then you would suggest -- at 16 least this is the way I see the logic of it, is that the 17 fixed charge cannot under those -- or should not be 18 strictly based upon the incremental cost. 19 MR. CLARK: No. I don't think it should be 20 the factor that falls out after the incremental charge 21 is set. Either that or you have a variable incremental 22 charge, which is as you increase the power maybe the 23 incremental charge steps down a little bit. It starts 24 at this level and then drops down. 25 MEMBER ZERKER: Right. So you get some small 26 number -- 27 MR. CLARK: So you have better co-ordination 28 from one size of customer to the next. || Vol. Pg.912  MEA 1 MEMBER ZERKER: So I'm learning anyway. 2 Thank you very much. 3 THE PRESIDING MEMBER: Mr. Vlahos. Thank you, 4 Dr. Zerker. 5 MEMBER VLAHOS: Thank you, Mr. Chairman. 6 Gentlemen, just a couple of areas. First of 7 all, is it your understanding that going to the new rate 8 structure is -- is this an option or it is mandatory? 9 MR. TUCCI: Going to the new unbundled 10 Appendix A approach? 11 MEMBER VLAHOS: Yes. Yes. 12 MR. TUCCI: What it is is a default if you 13 don't put in your own cost-of-service approach. 14 MEMBER VLAHOS: Is the expectation that most 15 systems, small systems in particular, may want to rely 16 on the guidance in the Handbook? 17 MR. TUCCI: Yes. I think maybe only a handful 18 of utilities are prepared or anticipating to do a cost 19 of service, which brings me to another question, I 20 guess. 21 MEMBER VLAHOS: I'm sorry. Let me just 22 rephrase that. 23 I have the option of continuing with what I 24 have, as long as I take out my cost of power. Is that 25 an option that the system has now? 26 MR. TUCCI: I don't think it has been proposed 27 as an option. 28 MEMBER VLAHOS: Chapter 3 of the Handbook says || Vol. Pg.913  MEA 1 "a distribution utility may either use this adopted 2 procedure or its own procedure, although justification 3 for the reasonableness of that procedure will be 4 required". 5 MR. TUCCI: Yes. 6 MEMBER VLAHOS: Okay. So you are saying that 7 if you want to go and do it your own way, you have to 8 provide all kinds of justification, such as cost of 9 service studies. And I am not going as far as that. 10 I am going to the rate design itself. I have 11 to recover a certain revenue from my two customer 12 classes. Call it that for the sake of argument. And 13 with respect to the residential class, I have a certain 14 rate structure now. 15 Why can I not continue with that rate 16 structure as long as I unbundle? And all that means is 17 taking the cost of power out for the time being. 18 MR. TUCCI: The problem is determining how to 19 take out the cost of power from the existing rates. I 20 think that is the difficulty we had before. Even if you 21 wanted to have a kilowatt hour charge, not have a 22 customer charge and you wanted a kilowatt charge that 23 ramps down, you would have to be making some guesses as 24 to how to do that. 25 What we know is what the cost of power is for 26 the entire class. We don't know what we are collecting 27 from individual customers. 28 The wholesale rates have a demand and energy || Vol. Pg.914  MEA 1 component, but the retail rates just have an energy 2 cost. The problem is that converting that charge across 3 the existing rates doesn't quite work perfectly. 4 We need to develop a methodology to do that 5 too. That is my point. It wouldn't be something you 6 could just do automatically. 7 MEMBER VLAHOS: I understand. This brings me 8 to my other point, Mr. Tucci, and that is: You probably 9 picked up some of Ms Kwik's hints or disappointment as 10 to why some of the things have not been discussed 11 earlier, and I think I am just being a little more 12 direct on that. I am very disappointed that it has not 13 been done earlier. This is the last hour of the last 14 day of the hearing. 15 We had a task force back in May. We had a 16 Handbook out in June. There were technical conferences, 17 meetings and conferences galore. I am just surprised 18 that the MEA was not able to alert the Board or Board 19 staff about those serious problems and try to address 20 that problem through some testing of Appendix A. 21 Can you assure me that the MEA will try to do 22 its best to assist? 23 MR. TUCCI: I think the problem is that 24 earlier we were told that we might have expected a draft 25 version of Appendix A as sort of a spreadsheet program 26 that would be made available. Most of the utilities, 27 when they heard this in the workshop, said: Okay, we 28 will wait for it and when we get it, we will run through || Vol. Pg.915  MEA 1 the numbers. 2 That's why only a handful of utilities have 3 actually tried to do it. 4 When others have tried to look at it, they 5 have found they weren't exactly sure how to interpret 6 some of the -- it required some interpretation and they 7 wanted a little more guidance in terms of figuring out 8 how to do this. 9 As I said earlier, I understood that people 10 got different interpretations and they might be getting 11 different results from that different interpretation. 12 So until we narrowed it down and understood exactly what 13 we were trying to do and clarified how these things 14 should be interpreted, utilities have been just waiting 15 for clarification. 16 It is only in the past week that I have 17 actually started pursuing and told them: You have 18 expressed to me in person that you think there are 19 problems with this. I need actually hard numbers to 20 demonstrate to the Board that there is a problem. 21 It got them going. They had to make some 22 assumptions, but they tried to put some numbers on the 23 table. That is why I was scheduled last, because I 24 needed the time to actually get something checked and 25 verified. It has been a couple of weeks trying to get 26 these numbers. 27 Only one utility has actually provided 28 something that I thought I could present, that I had || Vol. Pg.916  MEA 1 some confidence was doing the kinds of numbers that made 2 sense. 3 MEMBER VLAHOS: Did the MEA sense any of those 4 potential problems when the Handbook came out? 5 Directionally, if you want to take whatever you have now 6 and put a fixed charge and a variable charge, and you 7 put all of your costs on the fixed charge, you are going 8 to create some impacts for certain customers. 9 Directionally, that is not a science. 10 Was the MEA alerted early enough to approach 11 its members and say: Look, we have a problem here and 12 we have to figure it out before we get to the hearing? 13 MR. TUCCI: We have been talking with 14 utilities about this. I think one of the other problems 15 that has happened is that the utilities have been busy 16 with all these other issues. I have had a lot of 17 members that I have relied on for analysis that haven't 18 been available because they are on some other task force 19 or doing some other thing, and we have been stretched 20 thin. 21 It is only by making this a big priority that 22 I have at least Hal to work it out for me, because he 23 knew he was going to be on the stand with me. 24 I am not saying that Appendix A is completely 25 flawed. I am just saying that it requires some further 26 refinement. When we first looked at it -- what is 27 actually in Appendix A right now is a real utility 28 number, and it seems to have worked. It looked || Vol. Pg.917  MEA 1 reasonable. 2 What we didn't figure out was how the 3 market-based rate of return would impact those numbers. 4 I didn't realize at the time that the utility in that 5 example may be unique and that it doesn't necessarily 6 reflect the results that would come from other 7 utilities. We didn't test it, because we didn't have 8 the spreadsheet, and there have been so many things 9 going on that no one developed their own spreadsheet. 10 I just wanted to make sure that we caught this 11 before it was too late and just raise everybody's -- 12 just clarify that there is a problem. 13 We don't necessarily have the answers either. 14 We don't know yet exactly how to do this and make it 15 work properly. If we did, we would have had them three 16 months ago. 17 MEMBER VLAHOS: Thank you. 18 THE PRESIDING MEMBER: Thank you, Mr. Tucci. 19 As you know, I said earlier that if you could 20 provide some of that advice or guidance in your final 21 submission, it would be very helpful to the Board. And 22 besides that, I am sure if you can speak with Ms Kwik 23 and go over some of the details -- because I don't think 24 it is the sort of detail that comes across very well on 25 the transcript -- it would be helpful to her, I am sure, 26 and to other members of Board staff. 27 I would like to thank you for coming here and 28 sharing your views and concerns with us. I look forward || Vol. Pg.918  MEA 1 to the assistance your submission will provide us in 2 trying to deal with them. 3 Thank you very much, Mr. Clark; thank you, 4 Mr. Tucci. 5 MR. TUCCI: Thank you. 6 THE PRESIDING MEMBER: I think that was our 7 last submission. 8 MS KWIK: That is right, Mr. Chair. 9 THE PRESIDING MEMBER: Before I close off, I 10 would like to put on the record that I know people or 11 many parties will be making further final written 12 submissions to us, and the Board would be greatly 13 assisted if people can be as specific in their 14 recommendations and suggestions as they can be so that 15 we can convert things into items that may or may not be 16 included in a Rate Handbook. 17 For example, if people are talking about the 18 level of productivity factor that should be included, 19 some indication of what they think would be a reasonable 20 one if they are deviating from what has been proposed in 21 the Board staff's Handbook. 22 If they are talking about rate design, some 23 indication of what sort of rate design they think would 24 be appropriate as rates are moving to initial rates. If 25 they are talking about pricing flexibility options, the 26 proposal contains a 5 per cent adjustment of change, you 27 want to go between whether that should be zero, 10 per 28 cent or if they don't like what is in there. || Vol. Pg.919  1 With regard to transition costs and Z-factor 2 considerations, some indication of the items that people 3 think are appropriate for inclusion in transition costs 4 or Z-factors. 5 These are just examples of where specific 6 suggestions may be more helpful to the Board than 7 statements of concern or statements of "you could do it 8 this way". If you say "do it this way", give us some 9 indication of how that way is. 10 I just put this on the record. I hope people 11 read the transcript. I think the Board will be very 12 much helped if the final submissions are specific as 13 opposed to general. 14 With that, I thank all of the parties who have 15 been here. I thank the court reporters in particular 16 for their attention, and I thank Board staff, Ms Kwik, 17 Mr. Ritchie and Mr. Motluk, for the support they have 18 given us. I thank my colleagues for sitting here. 19 Thank you. 20 --- Whereupon the hearing concluded at 1700 21 22 23 24 25 26 27 28 || Vol. Pg.920  1 INDEX 2 PAGE 3 Hearing resumed at 0903 671 4 Presentation by David Wills and Paul Ferguson 672 5 on behalf of Upper Canada Energy Alliance 6 Questions by Board staff 696 7 Questions by the Board 698 8 Upon recessing at 1040 733 9 Upon resuming at 1100 733 10 11 Presentation by Andrew Roman on behalf of 734 12 Halton Hills Hydro and the City of Peterborough 13 Questions by the Board 755 14 15 Presentation by Robert Wright, Wendy Moore and 16 John McGee on behalf of the Federation of 794 17 Ontario Cottagers Associations 18 Questions by Board staff 811 19 Questions by the Board 814 20 21 Luncheon recess at 1340 831 22 Upon resuming at 1440 831 23 24 Presentation by Marika Hare, Judith Allan 832 25 and Stephen Cartwright on behalf of 26 Enbridge Consumers Energy Inc. and 27 Enbridge Consumers Gas Inc. 28 Questions by the Board 844 || Vol. Pg.921  1 INDEX (Cont'd) 2 PAGE 3 4 Presentation by Maurice Tucci and Hal Clark 875 5 on behalf of the Municipal Electric Association 6 Questions by the Board 885 7 Question by Board staff 890 8 Further questions by the Board 900 9 Hearing concluded at 1700 919 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 || Vol. Pg.922  1 EXHIBITS 2 3 NO. DESCRIPTION PAGE 4 5 4.1 Document entitled MEA Oral 875 6 Submission - Exhibit 7 (October 7, 1999)