547 1 RP-1999-0034 2 3 4 IN THE MATTER OF ss. 19(4), 57, 70 and 78 of the 5 Ontario Energy Board Act, 1998, S.O. 1998, c. 15, 6 Sched. B; 7 8 9 AND IN THE MATTER OF an Ontario Energy Board 10 Staff proposed Electricity Distribution Performance 11 Based Regulation Handbook 12 13 14 Hearing held at: 15 2300 Yonge Street, 25th Floor, Hearing Room No. 1, 16 Toronto, Ontario on Thursday, September 23, 1999, 17 commencing at 0903 18 19 20 21 22 23 TECHNICAL CONFERENCE 24 25 VOLUME 3 26 27 28 548 1 APPEARANCES 2 JENNIFER LEA/ Board Counsel, Board 3 MIKE LYLE 4 ROBERT WARREN Consumers' Association of 5 Canada 6 ROBERT POWER/ Hydro Mississauga, London 7 SEABRON ADAMSON/ Hydro, Oshawa PUC, Sarnia 8 ALEXANDER GRIEVE Hydro, St. Catherines Hydro, 9 Whitby Hydro, Petrolia PUC, 10 St. Thomas PUC, GPU Electric 11 Inc./GPU Services Inc. and 12 Collingwood PUC, ENERConnect 13 JACK GIBBONS Pollution Probe 14 PAUL FERGUSON/ Upper Canada Energy 15 DR. C.K. WOO/ Alliance 16 PETER FAYE/ 17 DAVID WILLS 18 MARK RODGER Toronto Hydro 19 RICHARD STEPHENSON Power Workers Union 20 DAVID POCH Green Energy Coalition 21 ELISABETH DEMARCO Lindsay Hydro, Flamborough 22 ZIYAAD MIA Coalition of Distribution 23 Utilities 24 ROGER WHITE ECMI 25 TOM ADAMS Energy Probe 26 MAURICE TUCCI MEA 27 STEPHEN CARTWRIGHT Enbridge Consumers Gas 28 BILL HARPER Ontario Hydro Networks 549 1 APPEARANCES (Cont'd) 2 KEVIN BELL Great Lakes Power 3 GERRY DUPONT Nepean Hydro 4 RICHARD BATTISTA Union Gas Limited 5 BRIAN McKERLIE Municipality of Chatham-Kent 6 MICHAEL JANIGAN Vulnerable Energy Consumers 7 Coalition 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 550 1 Toronto, Ontario 2 --- Upon resuming on Thursday, September 23, 1999, 3 at 0903 4 MS LEA: Good morning. Welcome to 5 the third day of the technical conference into the 6 proposed PBR Handbook. A couple of administrative 7 matters. 8 First, there were some folk yesterday 9 who were looking for copies of Exhibit B, which was the 10 package filed by the Upper Canada Energy Alliance. We 11 had made copies. It's available on the windowsill or 12 on the table over there. 13 Secondly, I have no further 14 information yet with respect to the hearing of the 15 motion which was filed by Mr. Power on behalf of his 16 utility clients. Unfortunately, I don't yet have an 17 update on that. 18 I think with us this morning we have 19 representatives from Toronto Hydro. Mr. Rodger, we 20 will turn it over to you. 21 MR. RODGER: Good morning, Ms Lea. 22 Thank you very much. 23 On behalf of Toronto Hydro this 24 morning we have two presenters. To my right we first 25 have Richard Zebrowski -- that's 26 Z-E-B-R-O-W-S-K-I -- who is the Manager of Rates and 27 Regulated Services at Toronto. 28 Next to Mr. Zebrowski is Ms Ginny 551 1 Tam -- that's T-A-M -- who is an economist with Tariffs 2 and Pricing at Toronto Hydro. 3 I would turn it over to Mr. Zebrowski 4 to start the presentation on behalf of Toronto Hydro. 5 RICHARD ZEBROWSKI 6 GINNY TAM 7 PRESENTATION 8 MR. ZEBROWSKI: Good morning. 9 Thanks, Frank. 10 Mark has done the introductions, and 11 together Ginny and I are representing Toronto Hydro 12 Electric System Limited. Our remarks will be very 13 brief today. Most of our concerns with the mechanical 14 and technical aspects of the draft PBR handbook have 15 already been addressed in our two written submissions 16 and will not be repeated here. 17 Today we would simply like to express 18 our support for the handbook and urge that the process 19 move ahead with no undue delays. 20 The handbook lists three overall 21 objectives that were used for establishing the first 22 PBR mechanism. It is our belief that the proposed 23 mechanism is successful in meeting these objectives and 24 we will explain why. The three objectives are found in 25 section 2.1.3 on page 2-3 of the handbook. 26 The first of these objectives states 27 that the mechanism: 28 "-- should allow all involved to 552 Toronto Hydro Panel 1 gain experience with PBR while 2 minimizing potential for bad 3 outcomes." (As read) 4 The first generation PBR scheme must, 5 therefore, be a balanced mechanism. It must balance 6 the competing needs of the customers with those of the 7 shareholder as well as the utility. It must balance 8 the needs of the OEB with those of the utility and the 9 marketplace. It must also balance the risks and 10 rewards the utilities will be expected to manage. 11 Due to the many markets and 12 regulatory uncertainty still facing us, it is then 13 imperative that this first generation plan be a 14 cautious mechanism. 15 Risks for the utilities must be 16 limited to avoid potential or severe financial setbacks 17 that could arise from adverse behaviours, whether 18 intentional or not. As well, it is quite clear that 19 the OEB is concerned with potential for excess profits 20 and, as a result, rewards have been severely limited. 21 This in fact is one area where Toronto Hydro believes 22 the plan does require some modification. 23 The handbook proposes the use of the 24 ceiling to limit a utility's allowed return on equity. 25 If the utility exceeds that ceiling, all excess profits 26 are to be returned to the customers and none to the 27 utility or shareholder. Hence, the use of an ROE cap 28 greatly curtails the utility's incentive to enhance its 553 Toronto Hydro Panel 1 productivity. 2 We would strongly advocate for the 3 use of a sharing mechanism in the event the utility 4 exceeds its ROE ceiling. This would provide the 5 utilities with a much needed incentive to seek 6 productivity improvements beyond what are now 7 encouraged in the proposed model. 8 With a fair sharing mechanism in 9 place, utilities could pursue cost saving measures more 10 freely with the knowledge that if their efforts are 11 more successful than anticipated, the shareholder will 12 at least be entitled to a portion of the additional 13 returns. 14 Apart from that, Toronto Hydro 15 believes that this handbook has provided a reasonable 16 mechanism for moving us ahead into a PBR regulatory 17 world. The mechanism is relatively risk free and 18 achievable. It provides an opportunity for all parties 19 to become accustomed to this new approach to regulation 20 and to begin building the appropriate cultures to 21 support it. An overly aggressive PBR scheme is clearly 22 not appropriate. 23 The Board consultants have spoken on 24 several occasions of their findings that utilities in 25 Ontario are already working efficiently. Our already 26 low relative costs leaves little room for meaningful 27 improvement in the customer's overall cost of 28 electricity. 554 Toronto Hydro Panel 1 The second objective of the handbook 2 calls for administrative simplicity and lighthanded 3 regulation. In other words, the regulatory process 4 must not only be effective, it must also be manageable. 5 With 270 municipal electrical utilities in the 6 province, it becomes evident how important this 7 objective is. 8 The proposed PBR plan is effective in 9 meeting its objectives. It is simplistic enough to be 10 successful in the first generation. To add further 11 complications would create a greater regulatory burden 12 and risk, a lack of understanding among the 13 participants. 14 The handbook's third objective is to: 15 "Establish a base for future 16 regulatory initiatives." 17 It also states that: 18 "There may be other regulatory 19 mechanisms that hold great 20 promise but which would not be 21 implemented at this time due to 22 lack of consistent data, 23 insufficient time or 24 insufficient resources." 25 (As read) 26 Thus, a price cap mechanism has been 27 proposed for all utilities. 28 This position was supported by the 555 Toronto Hydro Panel 1 OEB's task force on yardstick measures which studied 2 the possibility of implementing a yardstick PBR 3 mechanism. They felt it was not feasible given the 4 issues cited in the handbook in the available 5 timeframe. 6 Toronto Hydro also supports the 7 handbook's approach for the first PBR plan. A 8 yardstick methodology may be a more appropriate 9 long-term regulatory mechanism for many of Ontario's 10 utilities, but clearly not for the first PBR plan. 11 Furthermore, I would also like to 12 point out for the record that the most suitable 13 long-term regulatory mechanism for Toronto Hydro is to 14 continue under a price cap regime. 15 A yardstick approach for Toronto 16 Hydro is simply not appropriate due to its unique 17 circumstances. However, this discussion will be left 18 for another day, presumably when preparations are being 19 made for the second generation plan. 20 The timetable available to us before 21 the targeted market opening is very short and there 22 remains a great deal of work yet to be completed. We 23 realize that much has been accomplished. For example, 24 the Affiliate Rules Code and distribution licences have 25 now been finalized and issued. However, much more is 26 still under development, most notable being the many 27 market-related rules that are at various stages of 28 completion. 556 Toronto Hydro Panel 1 At this point it is unclear whether 2 the market will even open in the fall of 2000 as 3 planned. We are therefore left with a great deal of 4 uncertainty regarding the precise nature and operation 5 of our future market. 6 Because of this uncertainty, it is 7 extremely difficult at this time to construct a 8 thorough regulatory mechanism with strong incentives. 9 We believe the Board staff is therefore taking the 10 correct approach by defining a first generation plan 11 which is only intended to serve as an interim 12 mechanism. 13 This will allow time for the market 14 and its rules to more fully unfold and at the same time 15 provide the OEB with more time to study and develop an 16 appropriate regulatory mechanism for the long term. 17 In closing, we would like to commend 18 the Board staff and their consultants for the 19 tremendous amount of work that has been completed and 20 the results that have been accomplished. 21 Overall, we have a reasonably good 22 model before us that will move us forward. With some 23 revisions, it will serve us well in meeting the OEB's 24 stated objectives. It will allow the utilities to move 25 smoothly and easily into a new marketplace and, most of 26 all, it will ensure that our customers continue to 27 receive the excellent affordable service that they have 28 grown accustomed to. 557 Toronto Hydro Panel 1 That is the end of our remarks today. 2 Thank you. 3 MR. RODGER: The panel will be 4 available for questions, Ms Lea. 5 MS LEA: Thank you very much, 6 Mr. Rodger. 7 Who has questions for this panel? 8 Mr. Poch? Mr. Gibbons? 9 Mr. Stephenson? Mr. McKerlie? All right. 10 Does anybody have questions for this 11 panel besides the Board staff? 12 All right, then. I think we have a 13 few questions. Thank you for your kind remarks. 14 Please go ahead. 15 MR. CRONIN: Yes. Good morning. 16 MR. ZEBROWSKI: Hi, Frank. 17 MR. CRONIN: Thanks very much for 18 your input into this process. You had, I think, also 19 recommended, besides the reconsideration of a sharing 20 mechanism, that there be a three-year average. 21 MR. ZEBROWSKI: Yes. 22 MR. CRONIN: Could you elaborate on 23 that? 24 MR. ZEBROWSKI: I guess it first came 25 up -- and I'm guessing here, but I think it was the MEA 26 that initially proposed that in terms of if there were 27 large capital investments that would reap benefit in 28 terms of future gains. Basically they proposed a 558 Toronto Hydro Panel 1 three-year mechanism in order to balance that out over 2 that period of time. 3 When we also looked at it, we came up 4 with an issue regarding system losses. Every year the 5 utility will be measured in terms of their performance, 6 I guess, on system losses versus the five-year 7 benchmark that will be established for each utility as 8 well. The calculation of those annual losses is a very 9 imprecise kind of a calculation and can introduce great 10 variability, and with that it could produce great 11 variability in utilities' returns as well because 12 losses is a very large component of a distribution 13 utility's cost of doing business. 14 So that variability in the annual 15 losses, as I said, is really due to calculation errors 16 which over a period of time will average out from year 17 to year. Therefore, we felt there was an added benefit 18 in going with the three-year average in terms of 19 smoothing out this loss problem as well. 20 MR. CRONIN: Yes, I believe we had 21 talked at one of the meetings about the typical 22 utility's proportion of costs due to line losses being 23 in the range of 12 per cent. So I guess that would be 24 consistent with your view that it is a significant 25 enough element in the cost structure to try to smooth 26 out those variations? 27 MR. ZEBROWSKI: I would suggest even 28 larger than 12 per cent, probably more in the order of 559 Toronto Hydro Panel 1 20 to 25 per cent, maybe. 2 MR. CRONIN: The second question I 3 had: In your first submission you had talked about the 4 productivity factor, and I wonder if you could spend a 5 minute or two talking a little bit more about your view 6 of say the choices as you view them now with the new 7 information that might have gone up on the Web site? 8 Have you had time to look at that 9 information? 10 MR. ZEBROWSKI: I have. It 11 definitely makes the last five years look a lot better. 12 To be honest, Frank, one problem I do 13 have is I don't have a breakdown of the information, 14 for instance, the same way that you broke it down for 15 the input price index. I don't know the variability of 16 different utilities' results, for instance, or even the 17 year-by-year tracking of the productivity factors. 18 So I don't have quite the same level 19 of information. It is still at a very, very high 20 aggregate level and it is difficult to put some meaning 21 to that. 22 I think, based definitely on what we 23 have seen in the last five years, it makes things look 24 much more attractive and much more feasible than what 25 we originally had thought, based on the 10-year 26 averages that you first gave us. 27 MR. CRONIN: Right. Toronto Hydro 28 certainly had seen a fairly significant productivity 560 Toronto Hydro Panel 1 dividend from the amalgamation. But even prior to 2 that, if you look at the five-year experience of the 3 utility as you view it, would you be comfortable given 4 the pre-amalgamation experience of the company or of 5 the utility? 6 Would that give you a fair degree of 7 comfort with the choices that were being offered? 8 MR. ZEBROWSKI: It is difficult to 9 answer only because we were six separate companies 10 prior to that. I am not totally familiar with 11 everything that was happening within the other 12 companies at that time. So I really couldn't give you 13 a good feel on that. 14 MS LEA: Thank you very much. 15 Anything further, Mr. Rodger? 16 MR. RODGER: No, Miss Lea. 17 MS LEA: Thank you very much. I 18 would like to thank you for your attendance here today, 19 and we appreciate your contributions and assistance to 20 the Board that you have provided. 21 Is the Green Energy Coalition Panel 22 ready to proceed? 23 MR. POCH: Yes, we are. 24 MS LEA: Thank you. We will give you 25 a moment then. 26 While we are changing panels, I 27 wanted to note one transcript correction which kind of 28 leapt out at me, and that is at pages 388 to 459. I 561 Toronto Hydro Panel 1 think it was Dr. Bauer that was testifying and the 2 indicator on the upper right-hand corner of the page 3 has it as "OEB Panel". 4 I don't think we need to correct the 5 hard copies we have, but perhaps you can correct that 6 in the actual transcript record that you keep? 7 Thank you. 8 Mr. Poch, perhaps you could introduce 9 your witness and have the name spelled and so on for 10 the reporters. Thank you. 11 PAUL CHERNICK 12 MR. POCH: With us today is Mr. Paul 13 Chernick, C-H-E-R-N-I-C-K. 14 Mr. Chernick, you are the author of 15 "Designing the PBR System for Ontario Electric 16 Distribution Utilities to Facilitate Cost-Effective 17 DSM" which was -- 18 MS LEA: Mr. Poch, that is too fast. 19 Can you say it again slowly, please? 20 MR. POCH: Yes. My apologies. 21 "Designing the PBR System for Ontario 22 Electric Distribution Utilities to Facilitate 23 Cost-Effective DSM". 24 MR. CHERNICK: If that is a question, 25 the answer is yes. 26 MR. POCH: Yes. 27 Mr. Chernick, you attached a brief cv 28 as Appendix C to that document, but just for those who 562 Green Energy Coalition Panel 1 don't know you perhaps we can very briefly touch on 2 your qualifications. 3 MR. CHERNICK: I have been an analyst 4 and consultant in utility regulation, primarily 5 electric utility regulation, but also some gas work, 6 since 1977. I guess that is almost 22 years now. I 7 started out working with the Massachusetts Attorney 8 General doing this kind of regulatory work on the 9 utilities there and since 1981 have been a consultant 10 on a range of electric and gas utility planning and 11 rate-making issues. 12 I have testified in 160-some 13 proceedings including, I believe, three Ontario gas 14 company proceedings on lost revenue and shared-saving 15 incentive mechanisms. 16 MR. POCH: Let me ask you this: I 17 noted in Professor Bauer's evidence his first footnote 18 refers to work for NARUC, entitled "Performance-Based 19 Regulation in a Restructured Electric Industry", which 20 is by Bruce Biewald et al. 21 MS LEA: Could you spell that name, 22 please? 23 MR. POCH: B-I-E-W-A-L-D. 24 It is my understanding, correct, that 25 you are a co-author of that work? 26 MR. CHERNICK: Yes, I am. I believe 27 I also cite that. 28 MR. POCH: All right. 563 Green Energy Coalition Panel 1 Could I ask you then to briefly 2 summarize your evidence? 3 MR. CHERNICK: Yes. In a nutshell, 4 the point of my evidence is that implementing PBR as 5 proposed in the handbook without some relatively minor 6 modifications, but important ones, would be 7 inconsistent with the legislative framework and the 8 Board's policy as relates to encouraging energy 9 efficiency activities by utilities as those that have 10 been expressed in particular for the gas distribution 11 companies. 12 My evidence deals with two sets of 13 issues: cost recovery issues and rate design. 14 On the cost recovery problems, the 15 problems that I identify in my evidence can be easily 16 fixed in any PBR framework that has been proposed or 17 talked about in this process. But there are two that 18 really must be fixed, and those are the recovery of 19 direct costs and the recovery of lost revenues. 20 MR. POCH: By direct costs, you are 21 saying direct costs on demand-side management? Is that 22 correct? 23 MR. CHERNICK: Yes. 24 The direct DSM cost recovery issue is 25 really quite straightforward since they can simply be 26 added in as a -- or the variance from the prior or 27 embedded cost level can be added into the utilities' 28 price cap as a Z-factor in the terminology of PBR 564 Green Energy Coalition Panel 1 set-up or treated as a DSM variance account in the 2 terminology that is used for the gas utilities. 3 So that is really a very easy fix. 4 The lost revenue problem requires 5 just a little reworking of the formula in some way. 6 First, I would like to say that lost revenues would 7 essentially disappear as an issue if the PBR were based 8 on a revenue cap rather than a price cap. 9 Some of the issues that have come up 10 about when one rate can be raised and another one can 11 be lowered, and whether you can take a single rate and 12 split it into two sub-categories, or whether you can 13 merge existing rates, those issues would be somewhat 14 easier to deal with, I believe, under a revenue cap 15 where you are looking at a total cost cap and then you 16 can separately impose restrictions on moving costs 17 between rates. 18 The handbook sometimes seems to 19 suggest that each rate element, the customer charge, 20 the energy charge, the demand charge, if there is one, 21 would have to rise at exactly the -- or no more than 22 the allowed price increase. There are other places 23 where it suggests that revenues could be shifted 24 between classes. I think in some ways those issues 25 could be defined and dealt with in a more 26 straightforward way with a revenue cap rather than a 27 price cap. 28 But within the price cap system you 565 Green Energy Coalition Panel 1 can also quite easily deal with the problem of revenues 2 lost due to the utilities' DSM activities without 3 interfering with any of the other objectives of the 4 price cap. 5 The simple answer is that you would 6 simply treat the conserved energy as if it were sales. 7 There are units of energy service being provided to the 8 customer and if you want the utility to live within a 9 budget within a cap of the cost of providing a unit of 10 energy service to customers, then you want to include 11 the conserved energy along with the energy that is 12 delivered through the wires. 13 The equivalent on the gas side is a 14 lost revenue adjustment mechanism, or LRAM, which has 15 much the same effect although it is generally 16 structured in a slightly different way. 17 The third cost recovery issue that I 18 raise is the issue of incentives to actively encourage 19 utilities to be involved in demand-side management. 20 There I simply recommend that the Board leave open the 21 option of incentives that split the DSM savings between 22 the utility and its customers and then see whether any 23 utility or group of utilities makes a specific 24 proposal, rather than trying to define a method in 25 advance. 26 On rate design I identified three 27 points that were relevant to the development of DSM and 28 distributed generation and that I think were handled 566 Green Energy Coalition Panel 1 poorly in the draft handbook and should be corrected. 2 The first is that the value of the 3 incremental distribution cost assumed in the rate 4 design proposal is far too low. The value used in the 5 handbook is taken apparently from a secondary report 6 about a study done in the 1980s. 7 That value has to be corrected for 8 inflation. The utility's overhead costs, most of which 9 are variable, should be added in. And the value has to 10 reflect the differences in avoidable distribution costs 11 or incremental distribution costs by voltage level. 12 The value that is being used is an 13 aggregate over customers who are served at transmission 14 voltages, distribution voltages and high and low 15 voltage within distribution. 16 The handbook also incorrectly asserts 17 that the value that they are starting with, which is in 18 1986 dollars I believe, had some loss component in it 19 which apparently it never had. 20 The result is a very low residual 21 incremental distribution cost estimate of about 22 $3.7 per megawatt hour. While this is just formally a 23 default value, it would be a difficult value for most 24 utilities to overcome because they don't have a large 25 enough dataset to redo the analysis and they would have 26 to go to some effort and deal with an unknown process 27 with the Board to overcome it. 28 So this presumption, this presumptive 567 Green Energy Coalition Panel 1 value may be very important in terms of determining 2 rate design in the future in Ontario. 3 With the correction that I have 4 identified, that estimate goes from $3.7 per megawatt 5 hour to over $14 per megawatt hour and, at least for 6 the example offered in the handbook, that correction 7 raises the share of residential distribution costs that 8 would be recovered through the energy charge from about 9 a third to 100 per cent. So it obviously makes a big 10 difference in terms of rate design and the incentives 11 for conservation, because customer charges don't 12 provide any such incentives. 13 The second issue on rate design is 14 that the -- 15 MR. POCH: Let me just interrupt to 16 say we have provided a copy of that study that we were 17 able to obtain to Ms Kwik and Board staff, so it will 18 be available to the Board and any intervenors 19 presumably can obtain a copy as well that way. 20 MS LEA: Thank you. 21 When I actually have it in my hand -- 22 I guess Ms Kwik has it -- I will give it an exhibit 23 number at that time. 24 MR. POCH: Thank you. 25 MR. CHERNICK: The second rate design 26 issue is that the handbook proposes that for classes 27 that have demand meters all of the variable 28 distribution costs should be recovered through the 568 Green Energy Coalition Panel 1 demand charge. That recommendation is inconsistent 2 with nearly 40 years of utility rate design experience. 3 The fact is that customers with high 4 non-coincident peaks, which is what is measured by a 5 demand meter -- a demand meter doesn't measure the 6 customer's contribution to the utility's peak but 7 rather the customer's own peak during the month, 8 whenever that occurred. 9 Customers with high non-coincident 10 peaks but low energy usage are cheaper to serve than 11 customers with the same peak but high energy usage, 12 because they are less likely to be at or near their own 13 peak at the time that their feeder is peaking or their 14 substation is peaking or the transmission line serving 15 that substation is peaking. Also, because of their 16 lower energy use, they put less stress on thermally 17 limited equipment such as underground lines, 18 transformers. 19 So some substantial portion of 20 distribution costs should be recovered through energy 21 charges even where demand charges are available. 22 Where time of use energy charges are 23 feasible because the customers have demand meters -- 24 excuse me, have time of use meters, the demand charge 25 probably should be set very low to cover only the most 26 local of connection costs, those related simply to the 27 customer's non-coincident load with the peak period 28 energy prices recovering the rest of the distribution 569 Green Energy Coalition Panel 1 costs. 2 My final and much more general point 3 about rate design is that the Board should clearly 4 offer the opportunity for utilities to offer new rates 5 within the overall price cap. 6 Such rates may be necessary, for 7 example, to reflect the load shape benefits of 8 customers with self-generation. A kilowatt hour 9 provided to a customer that meets half of its load, 10 through photovoltaics for example, will be much lower 11 than the cost of a kilowatt hour to a customer that 12 isn't providing its own generation on sunny days when 13 certainly the summer peaking areas are likely to be 14 peaking. 15 As long as there is no dispute from 16 the customers about a proposed rate the review process 17 should be simple, quick and non-burdensome so that 18 utilities are encouraged to implement new rates where 19 those are appropriate. 20 Unfortunately, the handbook is 21 somewhat inconsistent about what new rates would be 22 allowed, and I understood Board's consultants to say, 23 from my reading of the transcript from Tuesday, that 24 the utilities would be allowed to switch revenues from 25 one rate class to another, but not to create a new rate 26 within a class because of concerns about rate revenue 27 shifting. 28 I think that sort of puts the issue 570 Green Energy Coalition Panel 1 backwards. You should be more concerned about 2 switching costs from industrial to residential 3 customers, for example, than about dividing the 4 residential class into two different groups with 5 different characteristics where there is some cost 6 justification for doing that. 7 That concludes my summary. 8 MR. POCH: Then let me ask you to 9 respond to a couple of specific objections, if you 10 will, to DSM being included as part of this handbook, 11 that were raised by Board staff in their opening 12 comments. 13 First, Mr. King, I believe it was, 14 suggested that if the IDC number is set appropriately 15 then there shouldn't be much of a problem necessarily 16 for utilities in pursuing DSM. Could you respond to 17 that? 18 MR. CHERNICK: Yes. I think that 19 that argument sort of misses the point. It sounds good 20 superficially, but when you think about the numbers it 21 is just not going to work. 22 The first problem, just sort of as an 23 aside, is that one province-wide IDC isn't going to be 24 right for everybody. It's not either across classes or 25 across utilities. So the idea that you would get the 26 IDC right enough to give the utility all of the correct 27 incentives without their thinking about their local 28 situation is, I think, a little bit wishful thinking. 571 Green Energy Coalition Panel 1 But more fundamentally, aside from 2 whether you could do that or not, the basis problem is 3 that the utility loses two things when it invests in 4 DSM. 5 First of all, it spends the money for 6 the energy conservation measures and the programs and 7 whatever supporting work is necessary: the analysis, 8 the audit, the procuring equipment, and so on. 9 The utility also loses revenues, 10 loses the marginal portion of the rate, the incremental 11 energy charge, for example, but of course that is being 12 saved by the customer. Whatever the utility loses in 13 revenues, the customer is saving. The customer is also 14 saving in transmission and generation costs. 15 So the utility is losing these two 16 components, one of which the marginal rate might be set 17 roughly equal to the incremental distribution cost. 18 Over time it is possible that the 19 utility would save the present value of that 20 incremental distribution cost and lose in revenues the 21 incremental revenues, which are about equal to the 22 incremental distribution cost, and that over 20 years, 23 if regulation stayed the same and if the company didn't 24 run into a return on equity cap or any other kinds of 25 difficulties with recovering costs for which there is 26 no underlying rate base, then the company might be made 27 whole for those lost revenues. 28 Now, that assumes regulatory 572 Green Energy Coalition Panel 1 stability and a bunch of other characteristics are 2 going to stay the same for 20 years. But there is no 3 way that the company is going to recover the 4 expenditure on DSM. The program may be cost-effective 5 if that expenditure on DSM is not only high enough to 6 cover -- be as high as the incremental distribution 7 cost, plus transmission charges, plus what the customer 8 is paying for generation services, plus environmental 9 externalities and therefore could be several times 10 larger than those lost distribution revenues. 11 So I think Mr. King's argument falls 12 down rather substantially for a distribution company. 13 It might work if you had a price capped, entirely price 14 capped integrated utility that was expecting to have 15 the price cap regime run in the same way without any 16 resets or revisions to the system for 20 years -- 17 which, by the way, I have never heard of. These 18 systems are usually recalibrated every three to five 19 years. 20 MR. POCH: I take it, in that case, 21 you are saying even if that part worked, they would 22 still be out the expense of the measure and delivery of 23 the measure itself? 24 MR. CHERNICK: The only way that his 25 proposal would work -- well now, actually, it wouldn't 26 even work for an integrated company because even there 27 the company has both the lost revenues and the DSM 28 expense. You can recover the lost revenues, if 573 Green Energy Coalition Panel 1 everything is set right, through your savings in the 2 long term, if you assume this perfect world where 3 regulation never changes and everything is totally 4 predictable, but you are never going to recover your 5 DSM costs. 6 MR. POCH: Ms Kwik and Mr. King also 7 raised the question of the appropriateness of including 8 anything pertaining to DSM in the Board's 9 pronouncements at this time prior to there being some 10 other process, a larger process, to determine if we 11 should be doing DSM in the new world and who should be 12 doing it. 13 Could you comment on that? 14 MR. CHERNICK: First of all, it seems 15 that in terms of regulatory efficiency this is an issue 16 that has been pretty well settled. All of the 17 important components have already been decided in 18 Ontario and it is sort of silly to go back and spend a 19 lot of effort reworking it. There are lots of things 20 to do in the reorganization of the electric sector here 21 without rethinking this issue. 22 My understanding is that both policy 23 and law in Ontario are firmly behind the idea of using 24 utilities to facilitate energy efficiency. That is 25 certainly what the Board has decided to do for gas 26 distribution companies, even where customers are buying 27 their gas from third parties, not directly from the 28 utility; a very analogous situation to the electric 574 Green Energy Coalition Panel 1 distribution companies. 2 The Board consultants agree that 3 there are market barriers that prevent cost-effective 4 energy efficiency from being implemented. The markets 5 don't provide those services well. 6 We have lots of examples of that. We 7 have examples where, for example, in the heating oil 8 industry you have many suppliers, you have vigorous 9 competition, and some of those suppliers will 10 separately sign a contract to install a new furnace for 11 you or tune up your boiler, but they will charge just 12 as any other heating contractor would. 13 You don't have this kind of bundling 14 that you do with real DSM programs. You don't have the 15 long-term relationship between provider and customer 16 that allows the provider to take on a long-term 17 commitment to make an investment that will be covered 18 through rates over several years. 19 You have experience with electricity, 20 including places that have much higher electric rates 21 than Ontario and rates far above marginal cost, yet you 22 find that customers without utility intervention do not 23 do more than a very small percentage of the energy 24 efficiency measures that would be cost-effective. 25 So the concern about the utility 26 activity interfering with a competitive energy 27 efficiency market seems to me to be a complete red 28 herring. The energy efficiency markets just don't 575 Green Energy Coalition Panel 1 exist except for the largest customers and there only 2 for measures that are well-known relatively low risk 3 where the savings can easily be measured, where the 4 savings are so large that the energy service company 5 can pay for its contribution entirely out of its share 6 of the savings over a short enough period of time that 7 the measurement problem does not become severe. 8 Where you have those energy service 9 companies offering those kinds of services, DSM 10 programs can be designed to encourage them to go 11 further, to go deeper, to do a better job at a lower 12 cost to the customer. You don't have to eliminate that 13 service. You can build on it. 14 The other proposal that was bandied 15 about, other than somehow hoping that the market would 16 take care of the problem, was that of some regional DSM 17 entity. I think that is a good idea. 18 I have been involved to some extent 19 in helping to get one of those set up to cover the 20 state of Vermont. In Vermont, the regional state-wide 21 entity there is being formed basically by aggregating 22 up programs that were already being designed and 23 implemented for and by many of the utilities, in some 24 cases through associations of smaller utilities. 25 It seems that a good way to move 26 towards a regional entity is to have the utilities 27 create the infrastructure, become familiar with the 28 mechanisms, design programs, implement them, work with 576 Green Energy Coalition Panel 1 other utilities, form associations to develop programs 2 and deliver them more efficiently. Then, either if at 3 some point the provincial government decides that it 4 wants to mandate a top-down kind of structure, it can 5 use the resources that have been developed at the 6 utility level or if the government doesn't choose to go 7 that way, then the utilities, with the assistance and 8 support of the Board, can build up their local and 9 co-operative programs into eventually, if that is 10 efficient, a province-wide program or programs covering 11 wide areas within the province to capture the economies 12 of scale. 13 Even when you have done that, you 14 will still have the problem that that DSM effort will 15 tend to reduce the utilities' revenues, even if the 16 utilities aren't paying for it or even if it is coming 17 out of a special assessment that just comes off the top 18 and is flowed through as a Z-factor in each rate 19 reconciliation. 20 And if you don't address the lost 21 revenue issue, you will find that utilities don't want 22 to co-operate with the regional entity and will do 23 their best to undermine its efforts. And since you 24 want them to co-operate, you want the utilities to use 25 DMS to avoid their distribution additions where that's 26 cost effective, you want their special information 27 about their service territory to be available to the 28 co-operative or regional entities. 577 Green Energy Coalition Panel 1 You don't want to have that conflict. 2 So you are going to need to deal with lost revenues no 3 matter how you deliver this program. 4 MR. POCH: Thank you. 5 Those are the comments we have. 6 MS LEA: Thank you very much, 7 Mr. Poch. 8 Can I ask who has questions for 9 Mr. Chernick? 10 We will start with Mr. Rodger, 11 please. 12 MR. RODGER: Thank you, Ms Lea. 13 Just a couple of questions, 14 Mr. Chernick. 15 Your paper dealt, in part, with the 16 role of distributors for DSM in this new market. I 17 want to just explore that a little further with you. 18 Under the new legislative regime, all 19 local distribution companies can do is distribute 20 electricity. Any other activities -- generation, 21 energy marketing -- have to be done through other 22 affiliates. 23 So I'm wondering, first of all, what 24 your view is of the extent of activities that, if you 25 like, the wires companies can do in this market, 26 particularly in the context of the other new players in 27 the industry. 28 If you saw the Ontario Federation of 578 Green Energy Coalition Panel 1 Agriculture's submission, they talk about the 2 distribution company being the highway in the new 3 market. 4 So I guess the question is: What's 5 the role of the highway, with respect to DSM, in the 6 context of the other new players? 7 MR. CHERNICK: Well, I must admit I 8 haven't done a legislative analysis. I am not aware of 9 anything in the law that prohibits the utilities from 10 providing DSM services. 11 If they are not allowed to do that 12 directly, then the question is: What indirect 13 mechanism would be most efficient? 14 MR. POCH: Let me just interrupt to 15 say that, at least in the context of gas in Ontario 16 recently, there has been some interpretation that I 17 think the witness should be aware of, which is: There 18 was, I believe, the Orders in Council pertaining to 19 both Union and Enbridge Consumers inviting them to 20 curtail the regulated sector activities to the 21 distribution, storage and so on. There was at least no 22 objection to them including DSM in that definition of 23 "core". That certainly is the practice on the gas side 24 in Ontario. 25 So I'm not sure it's appropriate for 26 us to spend much time speculating on what would happen 27 if we had some other legal constraint imposed. 28 But, for the moment, I think this is 579 Green Energy Coalition Panel 1 quite hypothetical. 2 MR. RODGER: I'm simply asking what 3 the witness' view is of the new market. What is the 4 extent of the role, in his view, of what the wires 5 company can do to implement -- 6 MR. POCH: I guess I'm just asking 7 you to clarify. Are you asking him to comment on what 8 they can do legally, or what is best to be done from a 9 policy and economics perspective? 10 MR. RODGER: The question is based in 11 the context: if you assume that a distribution company 12 can really only do one thing, and that's distribute 13 electricity, what's the role of that entity with 14 respect to DSM in conjunction with other market 15 players. 16 MR. POCH: I guess I'm just asking 17 for clarification of the question. 18 Distribution in Ontario. Are you 19 defining "distribution" to explicitly exclude DSM? Or 20 are you leaving that as an open question? 21 MS LEA: Mr. Poch, it looked like the 22 witness maybe had an answer. Maybe he understands the 23 question. 24 Let's give it a try and if he 25 doesn't, then we will get further clarification, 26 please. 27 MR. CHERNICK: I guess it really 28 depends on what the purpose is of this limitation of 580 Green Energy Coalition Panel 1 the activity of the distribution utilities. 2 If the purpose is essentially an 3 accounting function, that you don't want the funds from 4 DSM commingled with the funds from distribution, then 5 it's easy enough to set up another entity reporting to 6 the distribution company -- which certainly could be 7 one of a regional utility service group; perhaps a 8 non-profit organization set up by a group of utilities 9 to provide these services currently. 10 I guess I would have to see specific 11 language about what it is they are allowed to do and 12 what it is they are not allowed to do. 13 If you want to posit a world in which 14 they are not allowed to do any planning, they are not 15 allowed to assist their customers in any way -- you 16 know, you can put so many restrictions on a utility 17 that you lose all potential benefits of having that 18 organization in place. 19 And I guess you really, also -- if 20 you are thinking about policy, you have to ask, "Well, 21 do we simply want a company that's in the business of 22 building roads and doesn't know or care about anything 23 else; doesn't know where they are going, doesn't care 24 where they are going, doesn't care who's using them, 25 how they are used, doesn't ask the question about 26 whether there should be a bus lane to encourage people 27 to stay out of their cars so that the highway doesn't 28 have to be widened, or do you want a company that 581 Green Energy Coalition Panel 1 simply builds highways and knows nothing else?" 2 I personally would prefer to have a 3 company that's thinking about what it's doing and how 4 best to serve the people it's there to serve. 5 MR. RODGER: In the example you 6 gave -- I think it was Vermont -- about the regional 7 DSM entity, did that concept evolve because it became 8 apparent that there was a different entity beyond, 9 perhaps, generators, distributors, retailers, that was 10 required that would be most effective to implement DSM? 11 Is that how that came about? 12 MR. CHERNICK: In that case, there 13 was a long period, about a decade, of sort of fits and 14 starts of utility enthusiasm about DSM and then a lack 15 of enthusiasm and pressure from the regulators to do 16 more and questions about cost effectiveness of the 17 utility's programs and whether they were using their 18 resources well. 19 Eventually, the regulators and the 20 public interest government agency intervenor, the 21 Department of Public Service, took the position that 22 it's just too hard pushing -- they have, I believe, 24 23 utilities; some of them are very small, meaning a 24 megawatt or less of load. Trying to corral all of 25 these utilities and move them in the same direction is 26 very difficult -- the utilities have multiple concerns 27 and conflicts -- and the simplest thing to do that 28 would be to set up this state-wide efficiency utility. 582 Green Energy Coalition Panel 1 The utilities basically went along 2 with this and have agreed to it. This was not 3 mandated, this was part of a settlement. They agreed 4 to it basically because it got them out of having to 5 justify what they were doing, justify that it was 6 cost-effective, justify that they weren't doing too 7 much or doing the wrong things. Also, they were under 8 a lot of criticism for having done too little. 9 The utilities may have felt that they 10 were always exposed to criticism along those lines. 11 They would just assume that somebody else would take 12 that responsibility. So they will be raising the money 13 through an assessment. The assessment will be 14 proportionate to the amount being spent in each utility 15 service territory to avoid cross-subsidization between 16 slow growing and fast growing utilities, for example, 17 but the planning will be done by this efficiency 18 utility and the implementation will be done by them as 19 well. 20 It should still be worked out about 21 the co-ordination of each utility's transmission and 22 distribution planning function with the DSM, because 23 one of the components that's built into this process is 24 trying to target DSM where it would be most effective 25 in avoiding distribution upgrade costs. 26 Does that answer your question? 27 MR. RODGER: Yes, I believe it does. 28 Just following on that point, what 583 Green Energy Coalition Panel 1 stage is this state-wide agency at? Is it now up and 2 running and implementing programs? 3 MR. CHERNICK: No. The Board held 4 hearings in July, I believe, on the settlement. Not a 5 whole lot gets done during August. The order, the last 6 I heard, was expected out some time this month and then 7 over the next couple of months they will be selecting 8 the contractors to run the efficiency utility. 9 I would expect it to be up and 10 running about the turn of the year. 11 MR. RODGER: Is Vermont a 12 jurisdiction implementing a PBR regime for its 13 distribution utilities? 14 MR. CHERNICK: No. It has 15 traditional cost of service rate making. 16 MR. RODGER: Just one final question 17 on the lost revenue problem. If I could just give you 18 a simple example, I just want to understand how your 19 proposal would fit into this PBR plan before the Board. 20 Let's say in the case of a 21 distribution utility through the expenditures on DSM 22 programs and the resulting loss of distribution sales 23 there was an overall loss in any given year of, let's 24 say, a million dollars, a million dollars less in 25 revenue. 26 MR. CHERNICK: Yes. 27 MR. RODGER: Under your proposal, how 28 would the utility make up that loss under this PBR 584 Green Energy Coalition Panel 1 approach? 2 MR. CHERNICK: The approach that I 3 have suggested would be, rather than look at the 4 million dollars, to look at the kilowatt hours saved. 5 That would presumably be something like a hundred 6 million kilowatt hours of savings. That would give you 7 a million dollars of lost revenues. 8 That hundred million kilowatt hours 9 would be included in the sales value as number of 10 kilowatt hours sold. Take the kilowatt hours sold plus 11 kilowatt hours conserved and divide that into the total 12 revenues to determine whether the company is under its 13 price cap or not. 14 Rather than asking the question "if 15 we take your revenues and divide it by your kilowatt 16 hour sales, are you within your price cap", you take 17 your revenues and divide it by your kilowatt hours sold 18 and conserved to do that check on whether you are 19 within the price cap. 20 Therefore, you would be able to have 21 a slightly higher price per kilowatt hour and still be 22 within the cap. 23 MR. RODGER: I see. So the bottom 24 line at the end of the day for the utility and the 25 shareholder, there is no adverse financial impact with 26 your approach. You would still make up that million 27 dollars. It would just be made up in another way. 28 MR. CHERNICK: That's my intention, 585 Green Energy Coalition Panel 1 yes. 2 MR. RODGER: All right. Thank you, 3 sir. Those are my questions. 4 MS LEA: Thank you. 5 Mr. Adamson, any questions? 6 Mr. Gibbons. 7 MR. GIBBONS: Yes, just one question 8 about a utility's short-run marginal cost of delivering 9 electricity. Let's ignore line losses for the moment 10 and assume the utility is not capacity constrained. 11 Would its short-run marginal cost of 12 delivering an extra kilowatt hour of electricity be 13 effectively zero? 14 MR. CHERNICK: Well, if by short run 15 you mean within this year, it would normally be zero, 16 yes. Even if you are constrained or close to it, you 17 would be looking at a cost that you probably incur a 18 couple of years out. So for most utilities, short run 19 would be zero as in losses. 20 MR. GIBBONS: Right. So the 21 short-run marginal costs would definitely be below 22 their incremental level as proposed in the Board 23 staff's handbook for that incremental distribution 24 charge? 25 MR. CHERNICK: Yes, because that's 26 mostly long-term indefinites that you would make in two 27 years or five years or ten years as a result of low 28 growth. 586 Green Energy Coalition Panel 1 MR. GIBBONS: Thank you. Those are 2 my questions. 3 MS LEA: Thank you, Mr. Gibbons. 4 Mr. Stephenson, Mr. McKerlie, 5 Mr. White. 6 MR. WHITE: Yes. You expressed in a 7 comment that you had some background in pricing of that 8 product. Have you looked at what the boundary issues 9 might be within the general service rate issues 10 according to the PBR handbook for those demand 11 customers versus non-demand customers? 12 MR. CHERNICK: I could take a guess 13 at what you mean by boundary issues. Would you like to 14 be a little clearer about it? 15 MR. WHITE: Okay. 16 MR. CHERNICK: I could give you three 17 or four answers. 18 MR. WHITE: I might even be 19 interested in all of them, but I may be the only one in 20 the room interested. 21 When you set up customers who you say 22 use a boundary of 50 kilowatts and you say all 23 customers below 50 kilowatts will be treated as one 24 class and all customers above 50 kilowatts will be 25 treated as another class from a revenue perspective, 26 based on your experience with utility customers, would 27 customers move across that kind of a boundary and what 28 might precipitate it? 587 Green Energy Coalition Panel 1 MR. CHERNICK: A small store can put 2 on an addition and move beyond the 50 kilowatt level, 3 for example, or in addition to expanding space, it 4 might add a new refrigerated section or something else 5 that uses a lot of electricity and move beyond the 6 boundary. 7 There may even be situations, 8 depending upon how your rate design process works, 9 where it's cost effective for the customer to claim to 10 be above the boundary because small customers on the 11 large class actually have lower bills than large 12 customers in the small class, and then to get on to the 13 higher category rate, they get the demand meter 14 installed and then hope the utility doesn't bounce them 15 back down again. 16 These are issues that utilities and 17 their regulators can spend a lot of time agonizing 18 over, trying to get the general service rates to fit 19 together in a way that makes sense and to work out the 20 rules for it. 21 If customers don't want to move up 22 because being a small customer on the G2 rate is more 23 expensive than being a large customer on the G1 rate, 24 when do you force them to move? When do you decide 25 that they probably are over 50 kw even though you don't 26 have a demand meter on them? 27 Those are not issues that I think you 28 can settle simultaneously for two hundred and some 588 Green Energy Coalition Panel 1 distribution utilities with a single rule, given the 2 variety that you are going to see in the rate levels, I 3 would expect. 4 MR. WHITE: Just so that we don't 5 focus only on the growth side of the equation, can you 6 see energy conservation activities causing a customer 7 to drop below the 50 kilowatt level? 8 MR. CHERNICK: Certainly, or simply a 9 change in the nature of the business. Just as a 10 retailer could add a refrigerated section, they could 11 also decide to take out that section and use it for 12 some other activity that uses a lot less electricity, 13 but generates greater sales and wind up being a smaller 14 customer. 15 MR. WHITE: Have you looked at the 16 typical Ontario rate structure before the unbundling 17 process? 18 MR. CHERNICK: I haven't. 19 MR. WHITE: Okay. 20 MR. CHERNICK: At least not since I 21 worked on the demand supply plan about ten years ago. 22 MR. WHITE: Okay. When you had 23 energy included in the price of the product, both 24 commodity and demand charges for the general service, 25 they typically were blocked in the same way it was in 26 Tennessee Valley Authority or other utilities across 27 the United States. 28 If you were to look at blocking the 589 Green Energy Coalition Panel 1 IDC and transferring some of that responsibility from 2 the energy charge to a demand charge at a certain 3 threshold, would that be a reasonable mechanic to 4 reduce threshold issues within an artificially-created 5 class created by the imposition of a 50-kilowatt 6 demand? 7 It seems to do that now within the 8 price structure that includes both energy and 9 distribution costs. So it seems to me that 10 conceptually it should be able to be done with just the 11 distribution costs. 12 MR. CHERNICK: So that for example, 13 the distribution charge would be one cent per kilowatt 14 hour up to some number of kilowatt hours and then 15 beyond that there would be a demand charge and the 16 energy price would fall? 17 MR. WHITE: The IDC component, yes. 18 MR. CHERNICK: That seems like a 19 reasonable way of dealing with the fact that you will 20 have some customers with demand meters and others 21 without, to have a smooth transition from an all energy 22 variable distribution rate to a variable distribution 23 rate that is part energy, part demand. 24 As a matter of fact, I can't think of 25 how else you would do it if you had both of those 26 groups of customers within a single class. 27 The other way they are talking about 28 it is just to make them different classes. If you have 590 Green Energy Coalition Panel 1 a demand meter you are on the demand rate, and you are 2 charged one set of rates which on average will be very 3 similar to what you would be charged if you were in the 4 non-demand metered class and just being charged for 5 energy, but it gives some reward to higher load factor 6 customers. 7 So you can do it as separate rate 8 classes. You can do it as blocks within a rate. I 9 have seen it both ways. 10 MR. WHITE: By establishing the two 11 classes that you suggested, would you not fall back 12 into the other problems about when a demand meter must 13 be installed and threshold issues like that which may 14 create an artificial advantage for some customers if 15 you have a utility that doesn't say aggressively 16 monitor the demand of individual customers around that 17 boundary issue. 18 MR. CHERNICK: I think you have the 19 same problem whether it is in one rate or two separate 20 rates, because you would still have the problem of if 21 you don't have a demand meter and you are only being 22 charged kilowatt hours, at what point -- how many times 23 do you get over what kilowatt-hour threshold before the 24 utility decides it is time to go put in a demand meter 25 and then start charging you a demand charge any time 26 your kilowatt hours go over the threshold? 27 Like I say, you either call it one 28 rate or you can take that first block and call it a 591 Green Energy Coalition Panel 1 separate rate and have them work out so that they are 2 essentially the same revenue effect. 3 The problem comes up when you wind up 4 with a real discontinuity at the edge of a rate or at 5 the edge of an option, as in this case where you could 6 have a situation where if you are charging for the 7 demand meter then small customers, especially small 8 customers who expect to be low load factor, are going 9 to want to stay off that demand meter, regardless of 10 whether you say you are moving from the G1 rate to the 11 G2 rate or whether you just say you are now moving from 12 the unmetered G rate to the metered G rate. 13 I don't think that you have got a 14 real substantial difference there. I don't think it 15 matters whether you call it different rates or 16 different blocks within a rate. But it is a problem of 17 rate design, of getting the pieces to fit, and it is 18 not going to fit for everybody. There will be 19 customers for whom any particular set of rules will be 20 disadvantageous to somebody, and there will be some 21 arguments for why this set is unfair and you should 22 have a different set. There is no perfectly 23 satisfactory way of doing this. 24 But I don't think combining it into 25 one rate really helps, because you can think of the two 26 rates, really, as the first rate is simply the first 27 block of your combined rate and if you go above it you 28 wind up being moved to the other rate. 592 Green Energy Coalition Panel 1 MR. WHITE: What would you consider 2 to be an acceptable percentage shift as the customer 3 moved from one class to another class simply by the 4 addition of say one kilowatt of demand from a rate 5 design perspective? 6 MR. CHERNICK: Well, ideally you 7 would like your average or typical customer to see 8 almost no change, to be really indifferent as being a 9 large G1 or a small G2 customer. 10 The problem is that where you are 11 using these rate classes, not just for statistical 12 purposes, but you really have a different way of 13 measuring usage, you are moving customers on to 14 time-of-use rates or you are moving them on to a rate 15 that includes a demand charge, there are going to be 16 some customers who are going to see some substantial 17 changes in their bills because they are higher load 18 factor or lower load factor, mostly on peak, mostly off 19 peak. 20 MR. WHITE: Without the time-of-use 21 implications -- 22 MR. CHERNICK: The issue is the same 23 whether you are talking about demand metering or 24 time-of-use metering. You can wind up with the same of 25 effect on customers who just don't have the average 26 load shape. 27 Of course, in order to make these 28 things fit you have to know what the average load shape 593 Green Energy Coalition Panel 1 is for the customers who are at or near the margin. I 2 don't know how many of your utilities have that 3 information. 4 MR. WHITE: So what you are 5 suggesting now is that under the existing pricing 6 structure in Ontario, if the customer went from 50 to 7 51 kilowatts that there could be a substantial change 8 in their bill on a percentage basis? 9 MR. CHERNICK: If that happened to be 10 a particularly high load factor or low load factor 11 customer that certainly could be the case. 12 MR. WHITE: Because you are saying at 13 51 they suddenly get a demand charge? 14 MR. CHERNICK: Yes, that certainly 15 could be the case, unless of course you -- 16 MR. WHITE: I would suggest that that 17 is not the case, okay? 18 MR. CHERNICK: You can also set 19 things up so that for that first 50 kilowatts you are 20 being charged only the energy charge and only the 51st 21 kilowatt involved is a demand charge. 22 MR. WHITE: So you could do the same 23 thing with distribution costs? 24 MR. CHERNICK: Oh, yes. I am 25 assuming here that we are talking just about how the 26 distribution costs are recovered. But again, it 27 doesn't matter whether you call it two different rates 28 or blocks within a rate. The G2 rate, for example, 594 Green Energy Coalition Panel 1 could be set up exactly the same way and just have a 2 demand charge on demand over 50 kilowatts. 3 MR. WHITE: Thank you. 4 MS LEA: Thank you, Mr. White. 5 Anyone else besides Board staff? 6 Thank you. 7 Does Board staff have any questions? 8 MR. CRONIN: Yes, actually we do. 9 Mr. Chernick, would you agree that 10 the issue of restructuring the distribution industry in 11 Ontario is one that is still a complex? 12 MR. CHERNICK: I would say that is an 13 understatement. 14 MR. CRONIN: Would you agree that if 15 we only looked at the PBR section, or PBR aspects of 16 that, that policymakers in general and the Board in 17 particular have to consider multiple objectives? 18 MR. CHERNICK: Yes. 19 MR. CRONIN: Actually, I was 20 interested in your discussion about Vermont and I 21 wanted to follow up on a couple of questions that were 22 asked about that. 23 You had mentioned, I believe, that 24 there were 24 utilities in Vermont and you had 25 mentioned that -- did I understand that the one utility 26 that you had referenced, the one with a megawatt, would 27 that have been at the small end of the distribution? 28 MR. CHERNICK: Yes. The total load 595 Green Energy Coalition Panel 1 for Vermont is something on the order of 1,000 2 megawatts. 3 MR. CRONIN: Do you have any idea 4 what number of customers would be associated with the 5 smaller utilities in Vermont and what the average size 6 would be, approximately? 7 MR. CHERNICK: Well, there are these 8 municipal utilities that serve towns that nobody 9 outside of Vermont has ever heard of, really small 10 communities, essentially rural communities, and they 11 may have only a few thousand customers. 12 MR. CRONIN: Are you aware that the 13 number of utilities in the province -- and it probably 14 changes daily so we will only use approximations -- is 15 on the order of 250? 16 MR. CHERNICK: I have heard over 200 17 and about 250 being mentioned, yes. 18 MR. CRONIN: It's at least 250. 19 MR. CHERNICK: Okay. 20 MR. CRONIN: I believe also, and I 21 think this is documented in the exhibit in the staff's 22 opening statement, that there are over 100 of those 23 utilities that have less than 1,000 customers. In 24 addition, there are another 100 utilities that have 25 been 1,000 and 10,000. So we have clearly a very large 26 number -- or wouldn't you agree that we have a very 27 large number of very small utilities? 28 MR. CHERNICK: Yes. 596 Green Energy Coalition Panel 1 MR. CRONIN: So I am intrigued by 2 this discussion that you had had on the regional 3 implementation aspect of this. 4 One of the considerations that was 5 paramount in designing the rate handbook was one of not 6 only simplicity conceptually but also practicality from 7 an implementation perspective. Would you also be aware 8 that in fact some of these utilities have one or two 9 employees? 10 MR. CHERNICK: That sounds about 11 right for that size utility. 12 MR. CRONIN: So that unless we 13 designed a program that considered these factors, that 14 is how do you deal with a large number of very small 15 utilities in designing some kind of DSM program, it 16 probably would not be reflective of the realities of 17 the province? 18 MR. CHERNICK: Well, you have a large 19 number of small utilities, but you also have a large 20 amount of the province's load that is served by 21 relatively large utilities. So even if you only had a 22 DSM regime that really got to the customers who were 23 served by utilities with more 10,000 customers, you 24 would still have done a lot. 25 MR. CRONIN: Yes, from a customer 26 weighting perspective. 27 MR. CHERNICK: And from a load 28 weighting perspective. 597 Green Energy Coalition Panel 1 MR. CRONIN: I agree. 2 MR. CHERNICK: And from total 3 benefits. 4 Now, there is also the problem of 5 those smaller customers, smaller utilities, and I think 6 once these programs are up and running for large and 7 medium-sized utilities it becomes much easier for a 8 medium-sized city to offer to extend its program to the 9 rural communities around it, you know, to all the 10 little towns with 700 and 7,000 customers who, after 11 all, are shopping at the same stores and could be 12 picking up the same rebate forms, and it would require 13 a very limited amount of extra effort to fold those in. 14 But I certainly wouldn't want you to 15 throw out the -- I don't know what percentage it is, 75 16 or 80 per cent of the load that is served by the large 17 utilities, because you haven't yet figured out how to 18 get to the small ones. You can get to them either by 19 starting with the larger ones and creating a model and 20 trying to bring the small ones in. 21 The small ones also are probably the 22 ones that are most likely to aggregate either as 23 regional public entities or as private entities. I 24 suspect that there is already a lot of co-operation. 25 Seeing as how a company with one or two utilities isn't 26 going to be able to do much about fixing anything on 27 the system, then there is probably some joint action 28 and joint implementation going on. 598 Green Energy Coalition Panel 1 MR. CRONIN: Right. I'm not 2 contending that most of the customers and most of the 3 load isn't served by -- you know, it's probably the 4 80/20 rule. 5 I'm just basically talking about the 6 practicality that we have at least 200 pretty small 7 utilities and that whatever program is put in place 8 just has to basically consider that aspect of the 9 issue. 10 MR. CHERNICK: I certainly wouldn't 11 want to mandate something that would make life 12 miserable for those one or two employees of those 13 little utilities, and nothing that I have suggested 14 would be a mandate. 15 MR. CRONIN: No. That's why I'm 16 making the point that the regional concept that you 17 floated is probably something that needs to be 18 reflected on. 19 MR. CHERNICK: Well, it is certainly 20 the Board should encourage the utilities to work 21 towards that goal and the Board might also think about 22 what it could do to encourage the provincial government 23 to set up a mechanism to facilitate it. 24 But these things can be done without 25 legislative action, without a government mandate. As 26 they have been done in Vermont, they have this approved 27 by the regulators but it was basically worked out 28 between the customer advocates and the utilities. 599 Green Energy Coalition Panel 1 So I think you are right, the Board 2 should be concerned about getting DSM services to 3 everybody, and while the larger utilities are 4 encouraged to go forward and to think about 5 regionalization, the Board also ought to think about 6 how to bring everybody under one big tent. 7 We certainly wouldn't want to lost 8 the DSM programs that are already in place where you 9 would lose perhaps years of potential benefits for a 10 large portion of the customers in the province while 11 you work on an even better solution for the longer term 12 and the perfect is the enemy of the good. 13 MR. CRONIN: Maybe following, that 14 issue really I guess we could describe as one of the 15 implications of scale of utility operations with 16 respect to DSM. I was wondering if you might comment. 17 There were, I think, some discussions 18 that went back and forth over the first two days -- I 19 lose track -- that had to do with whether or not it 20 would be useful to consider DSM programs more 21 comprehensively; that is, here we are talking about the 22 distribution industry. There are obviously other 23 aspects to the electric industry as well as other 24 energy supplying industries. 25 Would it be useful for the government 26 or some body to consider a more holistic approach? 27 MR. CHERNICK: That might be useful 28 as well. 600 Green Energy Coalition Panel 1 I know in Massachusetts and some 2 other states the electric and gas utilities have gotten 3 together and sponsored programs jointly where those 4 affected both electric and gas usage and divided up the 5 costs among them. 6 Certainly, the Board could encourage 7 the gas utilities to work with the electric utilities 8 in providing a common set of new construction programs, 9 for example, so that you don't have people running back 10 and forth between the gas utility to understand what 11 kind of windows you have to put in to get their 12 incentives and back to the electric utility to see what 13 they require. 14 So that kind of thing would be very 15 useful. 16 It is my understanding the Board 17 doesn't have any authority over other fuels such as 18 oil. But again, if the provincial government wanted to 19 set up a new governmental entity, a new taxing 20 function, an assessment on all energy sold within the 21 province to fund energy conservation, that would be a 22 very desirable feature. 23 This is the sort of thing that has 24 been very difficult to get in place, and I can't really 25 think of an example of it in North America on a 26 widespread basis. 27 There are very small assessments to 28 support basically Ministry of Energy kind of analytical 601 Green Energy Coalition Panel 1 work, but in terms of delivering millions of dollars to 2 customers, I can't think of an example where that has 3 been done. 4 So that might be a project for well 5 into the next millennium. 6 MR. CRONIN: Well, yes. We are not 7 actually -- 8 MR. CHERNICK: Don't hold your 9 breath. 10 MR. CRONIN: Yes. 11 It does seem, given the discussions 12 that have transpired, that that broader holistic view 13 of this area might be beneficial. 14 This may not be -- I just want to 15 suggest this question, and it may be more rhetorical. 16 Neither one of us probably -- we are probably actually 17 the two worst to talk about this issue in the room. 18 I guess rhetorically I would ask: 19 What would be the best forum in which to deal with 20 these kinds of questions? 21 You have just talked a bit about it, 22 both with respect to the Board's authority as well as 23 more generally. Unfortunately, I guess I wonder if 24 this actual forum is the best place to do it. 25 MR. CHERNICK: It has actually been 26 my experience that it is often useful to have things 27 running on parallel tracks. 28 In particular, one of the things that 602 Green Energy Coalition Panel 1 the Board can do -- this is sort of an extension of the 2 idea that if you take away the disincentives for 3 utilities to pursue DSM individually and encourage 4 them, just with some kind words, to put together joint 5 activities which would simplify both the Board's 6 oversight and the utilities' filings, that you can 7 start to build up within the electric industry the kind 8 of co-operative regional, eventually maybe 9 province-wide activities, and the Board can encourage 10 the electric and gas utilities to work together and, in 11 doing both of those things, create a model on which the 12 government can build a more complete cross-fuel 13 program. 14 In the meantime, one, you get real 15 benefits on the ground in terms of energy conservation 16 measures installed; and, two, you get an experience 17 that allows you to go forward with greater confidence 18 about how these things would work. 19 If you can get a dozen utilities of 20 varying sizes working together on delivering programs, 21 and if you can get Enbridge, for example, to 22 participate in a program with them and work out the 23 cost allocations and so on, then this becomes a model 24 on which you can build a program that includes oil. 25 At that point, you probably need a 26 legislative action to implement it, but at least you 27 have something specific to take to the government and 28 say: This is how it works within the regulated 603 Green Energy Coalition Panel 1 distribution companies and we can see exactly how oil 2 would fit in here. I think it would give them a lot 3 more confidence about how to proceed. 4 So you don't have to wait for the 5 right forum. Sometimes the available forum gives you 6 concrete benefits and also advances the analysis that 7 you want done later in some broader form. 8 MR. CRONIN: I just had two brief 9 areas that I wanted to get some reflection on from you. 10 As you may be aware, although I don't 11 think you were here yesterday, we did talk a fair 12 amount about rate shock if the utilities will be 13 allowed to go to a market-based rate of return. There 14 has been a fair amount of discussion about what will 15 that mean for rates. 16 I believe the expectation is that the 17 distribution costs will be increasing pretty 18 significantly as utilities move to a market-based rate 19 of return. 20 Would you have any idea of what you 21 would expect the incremental cost on distribution would 22 be from the kinds of recommendations that you are 23 making? 24 MR. CHERNICK: It is going to vary 25 across utilities and how aggressive they are about 26 pursuing DSM. Some already have some programs built 27 into their costs, so we are talking here about 28 maintaining those rather than necessarily increasing 604 Green Energy Coalition Panel 1 costs. Others I would expect to be ramping up 2 relatively gradually as they get into it. 3 So I don't expect that it would be 4 anything that is showing up in percentage points. It 5 would be, you know, under a per cent rate increase. 6 But it really will vary. 7 For some companies it may be more, 8 especially where they have a lot of load growth, but it 9 may be avoiding high costs in the future. 10 MR. CRONIN: So you would think on 11 average it would be less than 1 per cent? 12 MR. CHERNICK: Oh, yes. 13 MR. CRONIN: And that for these 14 high-growth areas, it might be -- 15 MR. CHERNICK: It might be more, but 16 it might be avoiding a greater percentage increase in a 17 few years when you otherwise would have had to rebuild 18 the substation or run some major project to serve your 19 load growth. 20 MR. CRONIN: I think that is all. 21 MS KWIK: I just have one question. 22 You mentioned earlier that utilities 23 might start developing their DSM expertise while other 24 policy decisions are contemplated. 25 Are you assuming, then, that the 26 expertise at the distribution utilities really is not 27 existent yet? 28 MR. CHERNICK: Where it is existent, 605 Green Energy Coalition Panel 1 we don't want to lose it in the interim, and the 2 interim could be many years before some -- and, 3 unfortunately, based on my experience in various states 4 where we have been talking about this for a decade or 5 so, it could be a very long time before some broader 6 solution is developed. 7 You could lose all of the expertise 8 that you have developed. 9 I was also talking about, in terms of 10 expertise, the experience of building up these regional 11 organizations and working across utilities. That's 12 something that could contribute to a broader solution 13 in the future. So you would like to do that, as well. 14 But I'm sure that there are a lot of 15 utilities that could use some additional expertise and 16 program designs that could be improved and new 17 approaches that could be undertaken and provide useful 18 information and perhaps, eventually, staff a regional 19 or provincial DSM effort. 20 MS KWIK: How long, in your mind, 21 would it take for a program such as you have just 22 described to be up and running, as you say? 23 MR. CHERNICK: Well, for a utility 24 that has really done little or nothing in the past -- 25 maybe just passed along offers from Ontario Hydro -- it 26 could take -- I think, realistically, it's probably a 27 year and a half, two years, before you could hire the 28 staff and/or get your consultants in and figure out how 606 Green Energy Coalition Panel 1 you want to proceed and get your materials put together 2 and be ready to really move forward. 3 For a utility that already has some 4 programs or has some in-house expertise, it could be a 5 matter of months before you could get it up and 6 running. It could be -- you know, you could expand a 7 program or add a new program or radically change a 8 program very quickly. 9 Starting up requires some greater 10 effort. 11 And I'm assuming here, in both cases, 12 that we are talking about utilities that are large 13 enough to have some in-house expertise. 14 MS KWIK: Okay. Thank you. 15 MS LEA: Thank you. 16 Anything other questions for 17 Mr. Chernick? 18 Mr. Poch, anything further? 19 MR. POCH: Yes; just two follow-up 20 questions. 21 First of all, on that last matter, I 22 take it there is nothing in your proposal that would 23 preclude a smaller utility from simply contracting out 24 to people with expertise? 25 MR. CHERNICK: That's correct. 26 That's one of those things that might take a couple of 27 months to negotiate and then another month or two for 28 the utility that has the program to figure out which 607 Green Energy Coalition Panel 1 merchants you are going to market this through, who are 2 the plumbers who instal the water heaters and how you 3 are going to reach them in this area that may be a 4 little bit offset from the utility's own service 5 territory. 6 So, there, you might very well be 7 able to get some concrete results within six months 8 even. 9 MR. POCH: And just in response to 10 Dr. Cronin's penultimate question about the likely rate 11 impact of DSM, assuming it grows to be more widespread, 12 could you just distinguish between rates and bills for 13 us. 14 MR. CHERNICK: Well, yes. I mean 15 there are rate impacts from DSM but they are -- unlike 16 raising the rate of return for a utility, which simply 17 increases rates and increases bills, DMS will in many 18 cases increase rates, especially in the short term 19 before it's had a chance to back out all of those 20 distribution facilities that would otherwise be needed. 21 But it will have a tendency to 22 decrease total bills, not just from the distribution 23 charges but also decrease, much more importantly 24 probably, the generation and transmission charges. 25 So total outlays from customers, 26 while those are going up due to the change in rate of 27 return, will be going down due to DSM once you get the 28 DSM up and running. 608 Green Energy Coalition Panel 1 MR. POCH: I understand, through 2 Board staff's kind offices, that we now have copies 3 available of a document, entitled "Estimation of 4 Incremental Capacity Costs from Municipal Utility to 5 R-87-7", by Peter Choynowski, C-H-O-Y-N-O-W-S-K-I, with 6 a cover on it indicating that it was Exhibit 7.7.19 in 7 the DSP hearing. 8 I'm wondering if we can have an 9 exhibit number for that. 10 MS LEA: Thank you. 11 We will call it Exhibit C, please. 12 And there are copies on the windowsill for those who 13 need them. 14 EXHIBIT NO. C: Document 15 entitled ""Estimation of 16 Incremental Capacity Costs from 17 Municipal Utility to R-87-7", by 18 Peter Choynowski 19 MS LEA: Thank you very much, 20 Mr. Chernick, for your attendance here today. We 21 appreciate your assistance. 22 I think we will take a 15-minute 23 break, now, and return at 11:00 and begin the Energy 24 Probe panel, if they are ready to go. 25 --- Upon recessing at 1041 26 --- Upon resuming at 1103 27 MS LEA: Can we reconvene, please. 28 We have with us the Energy Probe 609 Green Energy Coalition Panel 1 panel and Mr. Stephenson. 2 Thanks very much, gentlemen. I 3 wonder if you could introduce yourselves and please go 4 ahead and make your presentation. Thank you. 5 TOM ADAMS 6 MICHAEL HILSON 7 MR. ADAMS: My name is Tom Adams 8 representing Energy Probe. With me is Michael Hilson, 9 H-I-L-S-O-N. The two of us are co-authors of Energy 10 Probe's position papers. 11 The remarks that we are going to make 12 today try not to overlap too much, reiterate or restate 13 the position paper, but try to expand on them by way of 14 explaining the logic from which they were authored. 15 Energy Probe has a number of 16 suggestions and comments on the PBR implementation 17 issues, but the primary focus of our presentation is 18 the rate increase inherent in the draft handbook and 19 our recommendations on what to do about it. 20 Many representatives of the municipal 21 utilities have argued in this proceeding that the 22 government's policy is to commercialize municipal 23 utilities. Without detracting in any way from this 24 comment but rather to expand on it, Energy Probe 25 suggests that the government's policy is also to cut 26 electricity rates for consumers. 27 In making this claim, we rely on the 28 Minister's speech in announcing the White Paper. We 610 Energy Probe Panel 1 rely also on the third sentence which refers to the 2 goal of "lower electricity prices" and several other 3 references in the White Paper, specifically with regard 4 to the rationalization of the municipal electric 5 utility sector. 6 Page 20 of the White Paper states the 7 government's intention that customers ought to be 8 protected in the process. The last sentence on page 20 9 states: 10 "Under the Government's plan, 11 when consensus on amalgamation 12 among utilities can not be 13 reached, the Ontario Energy 14 Board would be available, at the 15 request of the utilities, to 16 facilitate the process and 17 ensure that the interest of the 18 consumer are met." 19 A clear articulation, in our view, 20 that the government cares about the interests of 21 consumers. 22 The thrust of the approach that we 23 are advocating is to achieve the goal of 24 commercialization in the context of bringing in rates 25 at the lowest possible cost. 26 Ontario's electricity restructuring 27 is a major undertaking in which the rationalization of 28 municipal utilities is one relatively narrow but 611 Energy Probe Panel 1 important part. We think that the municipal utility 2 rate and institutional restructuring should be done in 3 ways that make sense, both for the long term success of 4 the LDC sector on its own and also in the context of 5 the whole sector reform in total. 6 The Macdonald Committee foresaw major 7 efficiencies from the municipal utility 8 rationalization. The OEB staff's studies see exciting 9 efficiency improvements available, but against this 10 backdrop we see this discussion focused on how much 11 distribution rates are going to rise. This is 12 counterintuitive to us. It's further counterintuitive 13 by considering the starting point for this 14 restructuring discussion. 15 On one hand we have got the old 16 Ontario Hydro as a starting point for part of this 17 electricity assessment restructuring and that contrasts 18 against the municipal utilities. 19 The old Ontario Hydro was 20 characterized by massive debts, unfunded liabilities, 21 contracts to buy power at above market prices, 22 sometimes on 50 year contracts, just a large number of 23 liabilities. 24 Compare that with the condition of 25 the municipal utilities: huge bank accounts of 26 unneeded surplus cash, virtually zero debt, long-term 27 capital needs paid upfront through contributions in aid 28 or paid out through annual rates, many utilities with 612 Energy Probe Panel 1 fancy new trucks on the road and also nice new head 2 offices, lots of corner glass. 3 With the old Ontario Hydro 4 restructuring, there is a major effort by many people 5 to move heaven and earth to make electricity rates go 6 down, but on the municipal utilities' side of the 7 ledger, the OEB staff has come forward with a plan that 8 makes the rates go up. 9 Does this picture seem backward to 10 you? It does to us. 11 We see the following as more or less 12 axiomatic. All municipal utility capital was derived 13 from customers with contributed capital from specific 14 customers and retained earnings from customers in 15 general. 16 We see no economic distinction 17 between these different forms of capital and consider 18 that they should be treated as one. In this regard, 19 Energy Probe is I believe in complete agreement with 20 many, perhaps all, the utilities represented here and 21 with what have been described as the private views of 22 Dr. Cronin and Mr. King, that retained earnings and 23 contributed capital are identical. 24 From the perspective of rate policy, 25 the only justification we can see for treating retained 26 earnings and contributed capital differently is what 27 might be described as a King Solomon's bargain. That's 28 one point. 613 Energy Probe Panel 1 Another point is that there has been 2 lots of discussion about consumers having to pay twice 3 for contributed capital if a return is allowed. The 4 same, in our view, double payment problem applies to 5 retained earnings. 6 A third point. If all prudently 7 invested capital from now on will be allowed an 8 appropriate and efficient rate of return, the financial 9 viability of LDCs into the future is assured. One of 10 the utility intervenors, Lindsay Hydro, in its first 11 submission, page 3, suggests that the proposed 12 treatment of contributed capital threatens its 13 financial viability. 14 For those espousing this view, often 15 referred to in this proceeding as the penalization 16 perspective, it appears to us that those advocates are 17 relying for their normative touchstones on a chickens 18 counted before they have hatched approach. 19 Leaving fairness aside and assuming 20 that all prudently invested capital from now on will be 21 allowed a fair and efficient rate of return and 22 adopting the usual Coasian assumptions about minimal 23 transaction costs, we can see no efficiency 24 implications from the decision of what return should be 25 earned on historic capital. The point is historic 26 capital is a stranded benefit. 27 From a marginal cost pricing 28 perspective, there is no a priori efficient way to 614 Energy Probe Panel 1 allocate or recover stranded costs or benefits. 2 Leaving aside the impact on the electricity 3 restructuring process, there are several solutions to 4 dispositioning historic contributed capital and rate 5 base capital. 6 Those options include but are not 7 limited to a windfall to municipalities that may or may 8 not yield a tax decrease, using the stranded benefits 9 to offset stranded costs or some form of special 10 dividend to customers of utilities, there may be other 11 options as well. 12 The efficient price for any good or 13 service is primarily a function of its short running 14 incremental cost. For natural monopoly goods, this 15 theoretical statement of efficient price is not 16 particularly useful. As a result, we have a regulator 17 to deal with the messy alternatives. 18 For monopoly services like LDCs, so 19 long as rates are properly designed so that marginal 20 use is equal with marginal cost, the fixed component is 21 not particularly important to the efficiency of the 22 outcome. Therefore, using stranded benefits to fund 23 stranded cost or to fund a rate reduction would not 24 impair the efficiency of the distribution rates, in our 25 opinion. 26 Here we move from what we consider to 27 be more or less axiomatic to recommendations that are 28 more judgmental in nature. 615 Energy Probe Panel 1 Under the proposed scheme, the OEB's 2 draft handbook, not the government's Bill 35, is 3 bestowing a windfall on municipalities by allowing the 4 distribution utilities to double charge for their 5 capital already paid by their consumers. 6 By allowing a massive leakage from 7 the electricity ratepayers to municipalities, the OEB 8 staff proposal will raise electricity rates, which in 9 our view contradicts the intention of the White Paper, 10 and we are very concerned will potentially impair 11 public support for electricity reform in Ontario. 12 I should remark here that in 13 commenting on the windfall to municipalities, I do want 14 to be sensitive to the concerns raised yesterday by the 15 Upper Canada Energy Alliance and their concern over the 16 use of the term "windfall." We have brought in our own 17 discussions some alternative language that may be less 18 inflammatory, and I am open to suggestions on a more 19 appropriate way to refer to it. 20 What we have here are stranded costs 21 left over from Ontario Hydro on one hand and stranded 22 benefits left over from municipal utilities. It would 23 be good if we could use the good to cancel its weight 24 of the bad in our view; and that is that the stranded 25 benefits in the municipal utilities could be used to 26 discharge their full weight of the stranded costs from 27 Ontario Hydro, but the OEB staff proposal defeats this 28 purpose. 616 Energy Probe Panel 1 Nothing in the government commitment 2 to rationalization of municipal utilities even hints 3 that municipalities should be allowed to win the 4 $6.8 billion lottery without even buying a ticket. 5 They made no investment, were subject to no risk, and I 6 think it appears that by an accident of oversight are 7 receiving an unintended benefit, the result of which is 8 simply to jack up electricity prices. 9 Some appear to suggest that rate base 10 be based on future sale prices. We are concerned that 11 this is a form of circular logic. If this regime is 12 allowed there is no theoretical limit on how high asset 13 value can go or how high prices can go. 14 Some utilities such as Nepean have 15 argued that their value is purely a function of their 16 rate base assets, suggesting the write-down of assets 17 by 50 per cent to cut that value that corresponded to 18 some portion of their capital would result in a halving 19 of their total asset price or market value. 20 This perspective is incomplete 21 because the sum, the value of the sum of the NPV of net 22 return in the efficiencies -- I'm sorry, I will restate 23 it. 24 This perspective is incomplete. The 25 value of the utility is a function of the sum of the 26 NPV of its rate of return and the efficiencies that can 27 be captured through the PBR formula. 28 If the Board adopts our 617 Energy Probe Panel 1 recommendation and ensures that there is no double 2 billing for already paid capital, utilities would still 3 have a market value if there are efficiencies -- a 4 positive market value and maybe a substantial market 5 value -- if there are efficiencies available to be 6 gained, which we are very confident there are. 7 Here is the punch line. In Energy 8 Probe's opinion, it is in the public interest for the 9 stranded benefits within municipal utilities to 10 continue to benefit electricity consumers. All future 11 cost, including the full and fair cost of new capital 12 should be recovered from users. 13 We contest the OEB staff view that 14 the MEUs have underpriced their output because of their 15 failure to earn a rate of return on the capital 16 employed. If this were true, how do we explain that 17 the utilities are debt free with huge excess of working 18 capital on hand? 19 The answer to this riddle is that the 20 municipal utilities have been in some ways overcharging 21 for their service relative to their costs, not 22 undercharging. 23 LDC investments normally take some 24 years after they are made before they break even. In a 25 normal utility this problem is solved by using debt and 26 equity financing to bridge the gap between when the 27 investment is made and when the pay-off is ultimately 28 obtained. This debt equity carries the cost reflecting 618 Energy Probe Panel 1 the time value of money and the risk. Financing allows 2 rates to be lowered in the short term and costs spread 3 to consumers that benefit from those assets. For a 4 stable or growing utility rates would tend to rise more 5 quickly if they were to fund capital in advance versus 6 financing over the longer term. 7 Generally speaking, current municipal 8 utility rates include normalized and expected capital 9 requirements. Even though the capital requirements 10 don't include any financing costs under the rate of the 11 return on the invested capital, the fact that they have 12 been accelerated relative to financing the assets 13 through their life expectancy means that existing rates 14 are about as high or perhaps higher than they would 15 have been had they been financed in the normal way. 16 Therefore, tacking on a market-based 17 rate of return to the existing rate is at least partial 18 and possibly complete double counting. 19 In the long run, Ontario's 20 electricity restructuring will ultimately be beneficial 21 to consumers, even if we award a windfall to the 22 municipalities. Awarding an unearned windfall just 23 delays the cross-over point by perhaps 10 or 20 years. 24 We have some additional remarks to 25 make on productivity and service quality indicators. 26 For a number of reasons, Energy Probe 27 believes that the 1.25 per cent productivity factor is 28 too low. Just in quick summary, we think that the 619 Energy Probe Panel 1 sample that was collected by the staff is a biased 2 sample that underestimates the potential. We are 3 impressed by the finding that after the rate freeze in 4 the last five years the productivity in municipal 5 utilities doubled, perhaps suggesting that just a 6 little scrutiny and competition from declining natural 7 gas rates have caused the LDCs to smarten up 8 significantly. 9 We were also impressed by Toronto 10 Hydro's statement that smaller-sized units in Toronto 11 Hydro's current size can find efficiencies easier than 12 the current utility. We are in total agreement with 13 Dr. Cronin's comment yesterday when he explained why 14 getting the most improvement out of the least efficient 15 utilities will be extremely beneficial for the 16 province. 17 With regard to service quality 18 indicators, we would hope that as soon as possible 19 performance statistics can be kept on the basis of -- 20 kept and collected and utilities judged on the basis of 21 the cost of outage impacts to society as a whole, not 22 just by customer number. The TD Centre may be one 23 customer, Tom Adams at 12 Sidfort Court may be one 24 customer. There is a big difference if you disconnect 25 us. 26 Reliability levels for service to 27 urban and rural customers should be differentiated. 28 Some standard for stray voltage should be introduced, 620 Energy Probe Panel 1 either by the Ontario Energy Board or by the Electrical 2 Safety Authority. We are in total support of the 3 concerns expressed by the OSA in that regard. We are 4 concerned that a phase out of volt metering should be 5 used as a quality of service indicator. We note with 6 approval that the proposed high-fixed low variable rate 7 structure proposed in the staff report would incent 8 LDCs to phase out volt metering where those 9 opportunities arise. 10 We note with concern Ottawa Hydro's 11 expression of concern about the losses from dry cork 12 transformers downstream, that had moved from downstream 13 of the revenue meter to upstream's revenue meter when 14 the utility moves from volt metering to individual 15 metering. We hope that that problem can be solved. 16 This is by way of conclusion, that we 17 think that the transition cost mechanism that has been 18 proposed provides opportunities for utilities to 19 recover their legitimate transition costs, but we also 20 suggest that some of those transition costs ought to be 21 negative and should be counted in any rebasing that is 22 calculated during the process of handling transition 23 costs. 24 For example, utilities that have not 25 had contributions in aid of construction policies in 26 the past will have higher rates than similar utilities 27 with contributions in aid policies. If in future a 28 common contributions policy is adopted the utilities 621 Energy Probe Panel 1 that just for accidents of previous history had high 2 rates and lower contributions are in a position to reap 3 a windfall going forward. We consider that a potential 4 ground for rebasing. 5 There may also be similar rebasing 6 considerations when utilities take DSM programs out of 7 regulation and move them into the competitive sector 8 where the costs of those programs under the OEB 9 proposal goes straight through to the shareholder. 10 Our final point is that one of the 11 overall objectives of the PBR process should be to 12 ensure as best we can that consumers have clear 13 information on the changes taking place in their 14 electricity supply and in their municipal distribution, 15 primarily so that customers know who to hold 16 accountable if their rates go up. 17 We are available for any questions. 18 MS LEA: Thank you very much. 19 Questions for Mr. Adams and 20 Mr. Hilson? 21 Mr. Rodger? 22 MR. RODGER: Just a couple of 23 questions, Ms Lea. 24 Tom, if I can just clarify, then, 25 what Energy Probe believes should be the starting place 26 for end use given your comments that really all the 27 "assets" of end use are contributed capital one way or 28 another. 622 Energy Probe Panel 1 Is your recommendation to the Board, 2 then, that the MEU rate base is essentially zero? 3 MR. ADAMS: Yes. 4 MR. RODGER: The idea of making 5 profit or making a return that has evolved through the 6 PBR Handbook, that has really been inadvertent, that 7 the government never intended that for at least the 8 first several years of the new market? 9 MR. ADAMS: I can't comment on the 10 intentions of those who were the authors. 11 MR. RODGER: Maybe if you clarify 12 your -- it was the reference to somehow this process 13 being an oversight of the legislation. Maybe you could 14 just explain that. 15 MR. ADAMS: I claim no oversight in 16 the legislation. 17 MR. RODGER: I was wondering how you 18 levelled in your own mind the point that the rate base 19 should be zero and yet the legislation explicitly has 20 things like a transfer tax and payments in lieu. 21 If the assumption of the government 22 or the legislature was to have a zero rate base why 23 would you have such taxes and proxy taxes right in the 24 legislation? 25 MR. ADAMS: Well, I can just refer 26 you to the remarks in the White Paper which suggest 27 that the government wants to see electricity prices 28 decline. 623 Energy Probe Panel 1 MR. RODGER: I guess I'm saying if 2 the expectation was that there would be no profit of 3 end use, there would be no need for transfer tax 4 provisions in the legislation. There would be no need 5 for payments in lieu provisions in the legislation. Is 6 that fair? 7 MR. ADAMS: The transfer tax captures 8 some of the profits of the efficiencies to be derived 9 from PBR, which was another of the objectives that was 10 set out in the White Paper. 11 In addition, I can refer you to 12 clause 148-2 of the Act where there is a discussion of 13 what ought to happen with historic contributions in aid 14 and there is a clear expression in the Act that they 15 were to be used for the benefit of the customers. 16 MR. RODGER: Those are my questions. 17 Thank you. 18 MS LEA: Thank you, Mr. Rodger. 19 Mr. Poch? 20 MR. POCH: Yes, just a couple. 21 I understand your point about no 22 meaningful distinction between the pools of capital. I 23 wanted to ask about how you would maintain the right 24 price signal assuming the scenario you do. 25 I took it that you were saying that 26 the end block at least needs to be set at marginal cost 27 so that we don't lose that. I take it you would agree 28 it is attractive, that that is a correct price signal. 624 Energy Probe Panel 1 MR. ADAMS: That's correct. 2 MR. POCH: By that you mean shorter 3 long-run marginal costs? 4 MR. ADAMS: We think efficient prices 5 are based on short-run marginal costs. 6 MR. POCH: You would agree, I take 7 it, for most utilities that is close to zero? 8 MR. ADAMS: Short-run marginal cost 9 is not particularly helpful in the distribution -- in 10 natural monopolies. You can't recover your revenue 11 requirement on short-run marginal cost. 12 MR. POCH: So the reality is, if they 13 have to recover revenue requirement it is more like -- 14 of necessity, it is more like long-run marginal costs. 15 There has to be something for foreseen capital 16 expenditures? 17 MR. ADAMS: That's why we have fixed 18 variable rates. 19 MR. POCH: All right. I'm just 20 asking, on the variable component of rates you would 21 agree that there has to be something in there that 22 reflects the avoidable or not capital expansion of the 23 system? 24 MR. ADAMS: A potential solution that 25 occurs to me to solve the problem that you are 26 referring to is some form of financial transmission 27 rights. 28 MS LEA: I'm sorry, I didn't hear the 625 Energy Probe Panel 1 last part of that answer. 2 MR. ADAMS: Financial transmission 3 rights. 4 MS LEA: Financial transmission 5 rights. 6 Thank you. 7 MR. POCH: Would you agree, though, 8 that leaving the asset value in the utility as it were 9 with the municipality to earn a return, to the extent 10 that that is incorporated into the end block of rates, 11 that could be seen as a proxy for IDC, for the capital 12 side of IDC? 13 MR. ADAMS: Are you referring to 14 historic capital? 15 MR. POCH: Yes. 16 MR. ADAMS: Can you restate the 17 question, please? 18 MR. POCH: If the assets remain with 19 the utilities, the value of those assets, they get to 20 earn a return, in other words, on that historic 21 capital, and that return is allocated, at least in 22 part, to the variable component of rates, would you 23 agree that would be a proxy, however imperfect, for 24 avoidable future capital costs? 25 That is, you wouldn't double count. 26 You wouldn't want to double count. If you were going 27 to put that in, then you wouldn't tack on in addition 28 some IDC? 626 Energy Probe Panel 1 In other words, one solution to this 2 double recovery problem is to treat the return on 3 existing assets as the capital component of IDC. 4 MR. ADAMS: I'm confused about the 5 relationship between what capital component there is 6 in IDC. 7 MR. POCH: Okay. I thought we agreed 8 earlier that of necessity you need -- to get the price 9 signal right you have to include in your variable rate 10 a signal reflecting what the avoidable capital costs in 11 the future are. 12 MR. ADAMS: You need a price that 13 reflects your going forward cost. The difficulty is 14 that these marginal costs are very difficult to 15 determine, right. You build the line and the fixed 16 costs are high, the marginal usage costs are very, very 17 low. 18 That is not to say that utilities do 19 not have variable costs, they do, and those variable 20 costs ought to be reflected. 21 Maybe I'm not understanding you. 22 MR. POCH: I had thought you had 23 agreed earlier, and maybe you hadn't, that the variable 24 component of rates needs, of necessity, to pick up some 25 fixed costs or forecast fixed costs. 26 MR. ADAMS: That may not be true. 27 MR. POCH: All right. Let me leave 28 it there then. 627 Energy Probe Panel 1 Thank you. 2 MS LEA: Thank you, Mr. Poch. 3 Mr. Power and Mr. Adamson, any 4 questions? 5 MR. POWER: No questions, thank you. 6 MS LEA: Thank you. 7 Mr. Gibbons? Mr. Stephenson? 8 Mr. McKerlie? Mr. White? 9 Oh, I'm sorry. 10 Mr. McKerlie, please. 11 MR. McKERLIE: I'm sorry about that. 12 MS LEA: No, that's fine. You have 13 to be awake. 14 --- Laughter 15 MS LEA: I'm sorry, I didn't mean 16 that quite the way it sounded. 17 MR. McKERLIE: Let the record reflect 18 I am comfortable with that statement. 19 MS LEA: And I apologize for it. 20 --- Laughter 21 MR. McKERLIE: There was some 22 reference through your comments about government 23 statements relative to lower rates, electricity rates 24 for consumers in Ontario. Would you suggest that the 25 government in that was referring to the all-in 26 delivered rate? 27 MR. ADAMS: I think that is the 28 primary concern. 628 Energy Probe Panel 1 MR. McKERLIE: Would you feel that 2 the government, in its thinking and design, expected 3 that every component in an unbundled system to in fact 4 reduce? 5 MR. ADAMS: The creation of the PIL's 6 regime suggests that that is not the case. 7 MR. McKERLIE: So in fact an increase 8 in distribution rates as designed by this structure, 9 should it be offset through reduction in charges for 10 other components of the system, would reach the same 11 objective? 12 MR. ADAMS: Yes. Potentially. 13 MR. McKERLIE: I was just wondering 14 if you feel the same way about the assets of OPGI and 15 OHSC, that they should be starting with a zero rate 16 base as well. 17 MR. ADAMS: OPG should not have a 18 rate base at all. A zero rate base. But I don't think 19 that is exactly what you meant. 20 With regard to OHSC, the rate base of 21 OHSC was a decision related to the financial 22 restructuring of the liabilities, sunk costs of Ontario 23 Hydro. 24 So I think we are maybe talking about 25 three different subjects here: the municipal utilities 26 where we have sunk benefits; OHSC where there is a sunk 27 cost management issue going on; and, OPG, which is a 28 non-rate base rate of return firm -- or regulated rate 629 Energy Probe Panel 1 of return. 2 MR. McKERLIE: I stand corrected on 3 the OPG comment. But it would seem to me that OHSC is 4 looking at a rate of return on rate base structure for 5 its operations, both transmission and distribution. 6 To continue the question, then, would 7 you expect that they would start with a zero rate base 8 as well? 9 MR. ADAMS: That is a situation where 10 there is a real investment, a real liability. The 11 customers didn't pay up front. This was a "fly now/pay 12 later" scheme and now it's the pay later. 13 MR. McKERLIE: Okay. 14 Do you recall the component in the 15 development of the residual stranded debt calculation? 16 There was a component that I understand reflected the 17 incremental sources of revenue from the various aspects 18 of the restructured industry. 19 Do you remember what that number 20 would be? 21 MR. ADAMS: The stranded debt, to my 22 knowledge, has not been settled and there have been 23 many public discussions and presentations by Ministry 24 of Finance at which some of those numbers have shifted. 25 There was a presentation July 9th and 26 there was another presentation in April and the numbers 27 are not consistent. 28 Help me understand your question. 630 Energy Probe Panel 1 MR. McKERLIE: There was various 2 lines in the -- you are right, it is a point of 3 discussion to date, but there were various expectations 4 in the development of the residual stranded debt which 5 reflected incremental sources of revenue from the new 6 business corporations that have been established with 7 the unbundling of the industry. 8 I'm wondering if you can give me a 9 ballpark of what that number has been in terms of 10 presentations to date. 11 MR. ADAMS: I don't have it with me. 12 MR. McKERLIE: My recollection is it 13 was in the several billion dollar range. Subject to 14 check, I would certainly be corrected if I threw out a 15 number in the order of 15. 16 MR. ADAMS: Fifteen billion? 17 MR. McKERLIE: To be serviced by. 18 Again, I could be corrected. 19 MR. ADAMS: There are payments in 20 lieu of taxes that we have referred to. There are 21 dividends that are anticipated from OHSC and OPGI. 22 There is a complex group of figures. 23 MR. McKERLIE: Would you agree that 24 if an MEU starting with zero rate base, their net 25 income would be lower? Although you have pointed out 26 ways that they can earn income on future investments 27 and cost savings, their net income would be lower than 28 under the mechanism suggested by the OEB. 631 Energy Probe Panel 1 MR. ADAMS: That's correct. 2 MR. McKERLIE: So to the extent that 3 has a negative impact on the expectations of the 4 government and the calculation of the residual stranded 5 debt to service that amount of money, what would be the 6 impact on the calculation of the residual stranded 7 debt? 8 MR. ADAMS: An alternative mechanism 9 for dealing with the problem that I think you are 10 referring to, although it is not a mechanism that is 11 available within the scope of the OEB's mandate, is for 12 the MEUs to absorb some of Ontario Hydro's stranded 13 debt. 14 MR. McKERLIE: I guess I'm not too 15 concerned where you put it. My question is: How is it 16 serviced? 17 If the revenue expectations put 18 forward by the provincial government in the management 19 of the residual stranded debt are lower through your 20 presentation I think than what was expected, then how 21 is that debt serviced? 22 As I understand the way that that is 23 calculated, the way the residual stranded debt is 24 calculated, it is a substraction formula and, as a 25 result, you would end up with a higher residual 26 stranded debt. Would you agree with that? 27 MR. ADAMS: That is certainly 28 possible. But under the scheme that we have proposed 632 Energy Probe Panel 1 there is more room for consumers to absorb a CTC charge 2 without seeing a rate increase. 3 MR. McKERLIE: Based on the current 4 formula -- and you are correct again in that it has not 5 been formally stated, but the current formula suggests 6 a CTC in the order of .6 cents with the calculation as 7 has been projected to date. 8 MR. ADAMS: Yes. 9 MR. McKERLIE: So if those revenues 10 are in fact lower, would you see the CTC actually 11 increasing? 12 MR. ADAMS: Yes. 13 MR. McKERLIE: If you are able to 14 control a rate increase on one component of the 15 unbundled market but you increase another component of 16 the unbundled market, I wonder if you would help me 17 understand how, as a net impact on consumers, we are 18 getting much further ahead. 19 MR. ADAMS: The net impact 20 differential relates to the leakage of dollars out of 21 the electricity system to the municipalities. That's 22 the problem. 23 Maybe I should explain. 24 When the dollars leave the 25 electricity system to the municipalities they are not 26 coming back. Mel Lastman is not going to send a cheque 27 to pay for some nuclear waste at Pickering, right? But 28 if we leave the dollars within the electricity system, 633 Energy Probe Panel 1 by keeping the distribution charge as low as we can, 2 then the CTC, the room for the CTC to recover costs 3 related to nuclear waste at Pickering is higher within 4 the rate envelope. 5 MR. McKERLIE: Do you foresee any 6 time in which point in time we might give up in 7 expecting the industry to actually service the stranded 8 debt and look for other ways of paying it? 9 MR. ADAMS: I do foresee that. It is 10 inefficient for the stranded cost to be recovered from 11 the electricity sector, and Energy Probe advocates that 12 it be recovered from the taxpayer. 13 MR. McKERLIE: It would seem to me, 14 then, we have just gone into a circle which suggests 15 that whether or not the revenue is heading back into 16 the municipality or whether or not the taxpayer is 17 paying it through the provincial government paying down 18 the stranded debt, I wonder if again the question would 19 be: Are we getting any further ahead? 20 MR. ADAMS: One of the things we want 21 to be very clear on is the specific identity of the 22 consumer, the municipal utility ratepayer, and the 23 provincial taxpayer. They may be the same person, but 24 they have different interests at each point of the 25 triangle. 26 So we want everybody on the triangle 27 to be responsible for their fair, reasonable costs, 28 right? 634 Energy Probe Panel 1 It matters whether I'm paying for a 2 stranded cost through my electricity bill or through my 3 provincial taxes. I care about the difference. It 4 affects the efficiency of the outcome. 5 The fact that I happen to be a 6 provincial taxpayer, a property taxpayer and an 7 electricity consumer is no comfort to me to allow just 8 a kind of willy-nilly cost allocation exercise with the 9 cost within those pockets, because I'm affected very 10 differently than everybody else is by the implications 11 of income tax versus property tax versus electricity 12 prices. 13 It is bad policy to adopt an approach 14 that doesn't differentiate and distinguish between the 15 interests of municipal taxpayers, the interests of 16 provincial taxpayers and the interests of electricity 17 ratepayers. 18 MR. McKERLIE: I guess it strikes me 19 that -- I would be more than happy to read Bill 35 20 again, but it strikes me that the government was pretty 21 consistent in its design, such that the electricity 22 industry would service the stranded debt and maximizing 23 the revenues from those would be a way to do that. 24 As a result, I think that the design 25 that is being proposed puts this electricity industry 26 into a common footing with the rest of the energy 27 industry and is a way to get things moving forward. 28 I apologize. That wasn't a question. 635 Energy Probe Panel 1 An editorial. 2 I'm actually finished with my 3 questions. Thank you, panel. 4 MR. ADAMS: Thank you. 5 MS LEA: Thank you, Mr. McKerlie. 6 Mr. White, you have reconsidered? 7 MR. WHITE: Yes. I have one 8 question. 9 To the extent that municipal 10 utilities have debt associated with the assets in 11 service, would you say that those debt-carrying costs, 12 at least, should be covered? 13 MR. ADAMS: Absolutely. 14 MR. WHITE: Thank you. 15 MR. ADAMS: I should have been more 16 precise. 17 MS LEA: Thank you. 18 Ms DeMarco? 19 MS DeMARCO: I just have a question 20 to ensure the accuracy of the record. 21 In the beginning of your comments, 22 regarding contributed capital, you made specific 23 reference to Lindsay Hydro, on page 3 of -- 24 MR. ADAMS: Their submission. 25 Page 3. 26 MS DeMARCO: Lindsay Hydro's 27 submission doesn't deal with contributed capital. 28 I wonder if you could -- and to be 636 Energy Probe Panel 1 accurate, it's the submission of Lindsay and 2 Flamborough Hydro. 3 MS LEA: That's Lindsay and 4 Flamborough Hydro? 5 MS DeMARCO: That's right. 6 Flamborough is spelled F-L-A-M-B-O-R-O-U-G-H. 7 --- Pause 8 MR. ADAMS: I'm referring to a 9 document under a covering letter from you, dated 10 August 18th, page 3, the first full sentence on that 11 page; and the sentence reads: 12 "As a result, competitive 13 benefits may be limited by the 14 base rate mechanism provided by 15 the PBR Handbook and the future 16 viability of small efficient 17 distributors will be 18 threatened." 19 (As read) 20 MS DeMARCO: Certainly, the sentence 21 can stand on its own. 22 But to put it in the context of the 23 contributed capital, if you read the full paragraph, 24 you realize this has nothing to do with contributed 25 capital? 26 --- Pause 27 MR. ADAMS: I stand corrected. You 28 are absolutely right. This paragraph refers simply to 637 Energy Probe Panel 1 past efforts for efficiency enhancement and not to 2 contributed capital. I misplaced my references. 3 MS DeMARCO: Thank you. 4 MS LEA: Thank you. 5 Mr. Mia? Board staff? 6 MS KWIK: I just wanted to get some 7 clarification on you talking about the proposal 8 resulting in increased rates. 9 What potential causes for the higher 10 rates in the proposal do you see as being in the 11 control of the Board in setting just and reasonable 12 rates for the electricity distributors and how the 13 Board could abate the rate increases resulting from 14 such causes? 15 MR. ADAMS: The factor that is within 16 the control of the Board is the determination of 17 starting rate base, and the corresponding starting 18 rates. 19 MS KWIK: Can you be a bit more 20 specific? 21 What we are suggesting right now is 22 that we establish initial rates for the first PBR 23 generation based on existing rates. 24 MR. ADAMS: Your proposal sees 25 existing rates plus market-based rate of return. 26 We consider that that market-based 27 rate of return is partial or complete double counting, 28 relative to existing rates, and that double counting is 638 Energy Probe Panel 1 a function of the treatment of capital. 2 MS KWIK: I don't understand how it's 3 double counting. 4 The methodology in the rate handbook 5 shows you how to calculate the differences in between 6 the market-based return and the rate of return that you 7 are currently earning; and that's the increase that you 8 would have in rate of return if you chose to go to 9 market-based rate of return. 10 MR. HILSON: In addition, in the 11 proposed rates, there would be the depreciation on the 12 net book value of the assets in the rate base, but 13 having paid for all the capital costs in advance. 14 The current rates are based on 15 unexpected or -- like, current dollar capital 16 expenditures; whereas depreciation would be based on 17 the weighted average of costs over the last 20 years, 18 when the utility may have been smaller and dollars were 19 less. So there's partial double counting. 20 Because the current rates are based 21 on current dollars capital expenditures instead of -- 22 under market-based rate of return, the depreciation 23 would be less than what you would expect for current 24 capital expenditures. 25 MS KWIK: I think I follow. That's 26 fine. Thank you. 27 MR. CRONIN: Mr. Adams, you had made 28 the statement that you thought that the default value 639 Energy Probe Panel 1 for productivity, the 1.25, was too low, and I believe 2 you suggested it should be increased. 3 Would you care to offer a more 4 specific recommendation? 5 MR. ADAMS: I don't feel secure in my 6 knowledge to offer a recommendation. I'm just making a 7 directional comment, only, not a quantitative one. 8 MR. CRONIN: Okay. In your 9 supplemental submission, you made a recommendation with 10 respect to the IPI, the input price index, and I wanted 11 to ask two questions about that. 12 You recommended that it be calculated 13 using weighted average, rather than simple average. 14 Our intent with the simple average was to facilitate 15 more of a sense of competition in that aspect of the 16 PBR. 17 Would that consideration -- 18 MR. HILSON: There's a higher number 19 of smaller utilities that weigh heavily on the average. 20 It's not stratified, at all. So there's a small number 21 of large utilities that don't have very much weighting 22 on the index. I guess it's just an observation that -- 23 MR. CRONIN: There's no alternative 24 way to do it? 25 MR. HILSON: Right. 26 MR. CRONIN: Could I surmise from 27 your suggestion on that point that other than that, in 28 general, you would support the use of this kind of 640 Energy Probe Panel 1 input price index? 2 MR. HILSON: Yes. 3 MR. CRONIN: Mr. Adams, you had also 4 mentioned in your opening remarks the issue, as you saw 5 it, of the benefits derived to the provincial 6 ratepayers from having incentive for the least 7 efficient utilities to improve. 8 I wonder if you could elaborate on 9 your statement? 10 MR. ADAMS: Happily. 11 What we want to do, I think -- where 12 the public interest lies with this electricity reform 13 is to collect the low-hanging fruit first, cream, skim, 14 whatever you call it, and then we will get into the 15 harder things later. 16 I want this electricity reform to be 17 able to demonstrate benefits soon up front, 18 demonstrably, to customers. 19 If it is true -- and there has been a 20 very interesting discussion in this room, and I am by 21 no means erudite enough to know where the balance on 22 the argument lies. But if it is true that the 23 utilities with high cost and low efficiency today are 24 the best prospects for making gains, I don't see any -- 25 I understand the perspective of those efficient 26 utilities who feel penalized, and so there's some 27 violation of their sense of fairness, but I think it's 28 strongly in the public interest that we not be guided 641 Energy Probe Panel 1 by their sensitivities on that fairness and we apply 2 ourselves to getting those, squeezing those 3 efficiencies as quickly as possible. 4 So the proposed mechanism appears to 5 me to have the effect of valuing highly, from a market 6 resale perspective, those utilities where there's the 7 most fat, the easiest to capture the benefits. 8 And so you have this kind of 9 apparently counter-intuitive situation where the very 10 efficient utilities might have a low value, 11 particularly under my proposal, the proposal that 12 Energy Probe has articulated, and the utilities where 13 there's lots of opportunity for easy pickings because 14 they are doing a lot of things stupidly right now that 15 appear to be backwards from the normal way of looking 16 at things. 17 But I am urging people to take a 18 different perspective on it. 19 From the point of view of protecting 20 the consumers of Ontario, that's the right outcome. We 21 should be fostering that kind of approach because it's 22 the one that's going to give us the benefits soonest. 23 Is that helpful? 24 MR. CRONIN: Yes. Yes, that's great. 25 Thanks. 26 MS LEA: Any other questions? 27 Yes, sir, please come forward. 28 Mr. Faye? Is that correct? Thank 642 Energy Probe Panel 1 you. 2 MR. FAYE: That's right, Ms Lea. 3 Peter Faye. Representing the Upper Canada Energy 4 Alliance. 5 Mr. Adams, in your opening remarks 6 you appeared to characterize municipal utilities as 7 profligate in their spending of ratepayers' money. 8 Did I understand that correctly? 9 MR. ADAMS: No, sir. That's not the 10 case. 11 If the municipal utilities were 12 profligate, we would see them loaded up with debt and 13 we would see their bank accounts empty. 14 MR. FAYE: So you didn't mean your 15 remarks on the new trucks, the expanses of corner 16 glass, as disparaging? 17 --- Laughter 18 MR. ADAMS: There are instances of 19 profound inefficiencies in the municipal utilities, and 20 many of those instances related to work rules, union 21 contracts and -- but I'm not a close enough observer to 22 give you all the instances. 23 My experience with the municipal 24 utility managers is that they have had public interest 25 concerns at their heart but have not been working and 26 incented in an environment where all of that effort has 27 been recognized. 28 MR. FAYE: Thank you. 643 Energy Probe Panel 1 Another question I have, a follow-up 2 to Mr. McKerlie's comments on OHSC -- and this is more 3 or less a clarification. 4 Do I understand your point of view to 5 be that because OHSC has financed their capital by way 6 of debt, by and large, that they are entitled to a 7 return to service that debt? Is that your position? 8 MR. ADAMS: That's correct. 9 MR. FAYE: But I understood 10 Mr. McKerlie's question to be "should OHSC start with a 11 rate base of zero", and I'm having trouble 12 rationalizing the two thoughts, that servicing debt is 13 paying interest and has little to do with a 14 market-based rate of return. 15 MR. ADAMS: OHSC's debt in the new 16 structure is a commercial debt not guaranteed by the 17 province. For them to be able to borrow efficiently, 18 they need equity for the protection of the debtholders. 19 MR. FAYE: Would you agree that 20 should the MEUs find themselves in similar 21 circumstances, holders of commercial debt that is, that 22 of rate of return would also be justifiable in order to 23 provide equity that would be suitable to bankers? 24 MR. ADAMS: All future investments of 25 municipal utilities, whether they are funded by equity 26 or by debt, ought to be recovered at market-based 27 prices. 28 MR. FAYE: Thank you. That's all my 644 Energy Probe Panel 1 questions. 2 MS LEA: Thank you. 3 Any other questions? 4 I would like to thank Mr. Adams and 5 Mr. Hilson very much for your appearance here today and 6 your presentation, your assistance to us in this 7 regard. 8 Thank you. 9 Mr. Power, is your panel ready to 10 come forward? 11 MR. POWER: Yes, ma'am, it is indeed. 12 Perhaps while just moving witnesses back and forth, 13 there are two administrative matters. 14 First there is a collection of 15 overheads which Seabron Adamson will be speaking to 16 which is on the left-hand side of the room here 17 entitled "Going Forward On First Generation PBR - A 18 Presentation to the Ontario Energy Board". 19 MS LEA: Thank you. Why don't we 20 give that Exhibit D, please. It will become part of 21 the record. 22 MR. POWER: Thank you. 23 EXHIBIT D: Collection of 24 overheads entitled "Going 25 Forward On First Generation PBR 26 - A Presentation to the Ontario 27 Energy Board" 28 MR. POWER: One other administrative 645 1 matter. 2 I was interested to see a letter from 3 Mr. Warren indicating that if the motion goes forward, 4 he would like to cross-examine Mr. Grieve on his 5 affidavit. 6 I'm not certain what he intends to 7 explore, but for him and for anybody else who is 8 interested, we would be delighted, if anybody wants to 9 throw any questions to us, to try and assist and 10 respond in writing back or make any admissions that may 11 be helpful. 12 MS LEA: Thank you. I don't think 13 Mr. Warren is here. Perhaps you can just communicate 14 that to him. 15 MR. POWER: I will indeed. 16 MS LEA: I don't know how else to do 17 it, unless he is reading this transcript or listening 18 in. 19 MR. POWER: Right; thank you. 20 MS LEA: Thank you. 21 SEABRON ADAMSON 22 PRESENTATION 23 MR. ADAMSON: Given how much we have 24 heard over the preceding days, I am trying to sort of 25 somewhat modify my presentation and its content. I 26 would really like to not try to go through and repeat 27 much of the information which I have presented with my 28 colleague Phil Burns in two fairly lengthy submissions, 646 Frontier Economics Panel 1 but really try to focus on one or two key issues, the 2 kind of policy aspects of those issues and a series of 3 what I think are fairly practical recommendations on 4 going forward. 5 I think we have kind of probably had 6 most of our economics debate that we need to have. I 7 do have a few comments on that line as regarding some 8 recent proposals. 9 In general, I would like to sort of 10 focus a little bit more on some sort of broad issues as 11 to how we got to here and, more importantly, how do we 12 go forward. 13 I would like to speak very briefly 14 and I certainly won't go through the length that I was 15 originally intending to because I think many of the 16 arguments have already been made by myself and many 17 others, as well as in the submissions on the 18 contributed capital issue. 19 Then I would like to offer a set of 20 recommendations on some other issues on today's 21 productivity factor on thinking about shared savings 22 mechanisms and on the preservation of cost saving 23 incentives from the first generation PBR mechanism to 24 the second. 25 We flip over to page 3. Why is it 26 important to get this right? 27 We heard from Mr. Emmet yesterday 28 that he thought that the differences were very small 647 Frontier Economics Panel 1 differences and really perhaps this wasn't worth 2 arguing about. I fundamentally disagree with that 3 position. 4 First and second generation PBR is 5 really kicking off a process which I suspect will 6 continue in Ontario for many, many years to come. 7 Having worked in some other jurisdictions that have 8 gone through this process and continue to go through 9 with them, I have seen some of the problems, I think, 10 that can be created by a process which in my mind, 11 certainly in England and Wales on the implementation of 12 price cap regulation, didn't really start off on a good 13 footing. 14 I think it's important to try and get 15 the homework right the first time to make the process 16 transparent enough and credible enough to all parties 17 the first time. I think doing that is probably worth a 18 bit of up-front investment. 19 Second, the sums involved are 20 actually pretty substantial. A 1 per cent difference 21 on return on equity is tens of millions of dollars 22 transferred per year I suspect between shareholders and 23 customers, so we are not talking junk change here. 24 Nor in the idea of a commercialized 25 LDC world, commercial companies, particularly regulated 26 companies, don't give up a 1 per cent return on equity 27 very easily. I think if you participate in any of the 28 rate hearings, cost of capital hearings, in 648 Frontier Economics Panel 1 jurisdictions that try to establish market based rates 2 of return, differences much smaller than that are 3 considered very significant. 4 Thirdly, this mechanism is not only 5 about how much money goes to shareholders. It's about 6 what kind of cost savings can be produced. A very 7 quick scan of some financial statistics for the LDCs as 8 a whole would suggest to you that well, gosh, the costs 9 are pretty high on an aggregate level -- it's a big 10 province -- in a year and relatively small shifts, even 11 over three years, in the total amount of cost savings 12 that might be incented is again significant numbers of 13 dollars. It could be in the tens of millions of 14 dollars. Again, we are not talking junk change. 15 Fourthly, we don't really know how 16 long this initial mechanism is going to go on. There 17 is a timetable in the draft handbook which I recognize 18 and recognize Dr. Cronin's and Mr. King's comments 19 yesterday about how long it may go on. I suggest that 20 the best laid plans of mice and men may go wrong. 21 We don't know really what the 22 legislative agenda is going to be on for a couple of 23 years. We don't know that might affect this process 24 going forward, no matter what the Board agrees in what 25 kind of initial time run right now. 26 Fifthly, there's a lot of change 27 going on and I suspect a lot of it is going on below 28 the surface at the moment. There are very substantial 649 Frontier Economics Panel 1 numbers of amalgamations, mergers and acquisition 2 transactions being considered at this moment in the 3 province. 4 Potential bidders, particularly from 5 outside the province, are operating on quite partial 6 information. Their perceptions of what values are 7 extend into the future but are at least partially 8 dictated by the rules of today. They have to 9 understand what's going to happen in order to value one 10 of these companies properly. If the rules of the day 11 are not perceived to be transparent, perceived to be 12 economically sensible, that value will be affected. 13 I have sat many times on the other 14 side of the table, which is sitting with a team of 15 bankers sitting around trying to value these types of 16 organizations in a commercial context, and regulatory 17 risks are not inconsequential at all. 18 It doesn't only go down to perceived 19 slight shifts in discounting cash flow over a couple of 20 years, but there is a substantial subjective element 21 attached, in my experience, to perceptions of 22 jurisdictions with higher or lower regulatory risk. 23 Finally -- and I don't want to get 24 too much into the pointy-headed economics stuff here -- 25 incorrect pricing of electricity tends to negative 26 impacts on the economy as a whole. This is a consumer 27 good and as an intermediate good. 28 I was rather, I guess, astounded by 650 Frontier Economics Panel 1 the position of Mr. Adams -- and it's what I have heard 2 from other people -- that really all these costs are 3 sunk; we don't need to do it. Therefore, we don't 4 really need to think about them; that everything should 5 be done on a pure SRMC basis, so economically it 6 doesn't really matter whether we value these things at 7 zero or one. 8 We all knew that in many industries, 9 especially regulated industries, prices are often 10 required to diverge from pure short-run marginal costs 11 to cover some form of fixed or sunk costs. There is 12 substantial economic literature which I would point 13 people towards on the theory the second best in pricing 14 would suggest perhaps how this can be done. 15 I might specifically point people to 16 the Ramsey pricing literature which has been pretty 17 widely employed in this context. 18 Every time there is some amount of 19 money to be captured, whether it is stranded debt from 20 the past that we simply can't walk away from because of 21 the financial consequences now, or the fact that huge 22 amounts of money have been spent to build a railroad 23 track and the cost of moving across it now is very 24 small, it is not an uncommon situation from a departure 25 from pure short run marginal cost pricing which have to 26 be considered in many industries. 27 There is I guess 100 years -- and I 28 suspect Dr. Cronin may be able to help me out -- on the 651 Frontier Economics Panel 1 timing of thinking gone into how this can be done. The 2 literature is not insignificant and it is actually a 3 pretty helpful thing. 4 No matter what happens, the debt has 5 to be paid back. It is coming out of somebody's 6 pocket. You don't get to walk away. 7 Ontario can't walk away from it. 8 Heaven and earth aren't going to allow that and 9 certainly the bond market is not. 10 That money is coming from somewhere. 11 Certainly, the economic experience would suggest it 12 probably needs to come from where it is going to affect 13 efficient consumption the least. That is the sort of 14 basic insight of Ramsey pricing. 15 A certain equity consideration might 16 also suggest that that should at least try to be tried 17 with who actually was consuming electricity and got the 18 benefit of that in the first place, even though we 19 recognize that, gosh, maybe the benefit people receive 20 doesn't really seem worth the amount that was spent on 21 nuclear power plants. 22 But the money has to come from 23 somewhere. Even if you collect it from taxes, that has 24 impacts on the efficiency of the economy. This goes 25 back for many, many decades on what are the impacts of 26 different types of taxation on economic efficiency. 27 So every time we collect it there is 28 a potential for distortion, even from taxes. Taxes get 652 Frontier Economics Panel 1 paid by people on consumption of items, on income, 2 whatever. So saying it is going to taxes does not 3 prevent the potential for substantial economic 4 distortion. 5 That is the end of my economic 6 pointy-headedness I hope. 7 Moving on to slide 4, I think most of 8 these points have already actually come out. I hope 9 that some of the thinking we put into previous 10 submissions and the little analogies about Oscar and 11 Henry and whatnot sort of help bring some of the more 12 basic issues that kind of underlie what seems to be a 13 very complicated practical issue. 14 In deference to Dr. Bauer, who I 15 don't think is actually here today -- which is a bit of 16 a shame because I changed my lingo a little bit -- I 17 didn't decide to call it retained earnings on this 18 slide on the left-hand side. I called it "retained 19 operating surplus", which is not a standard accounting 20 phraseology to my mind, but in deference to his 21 comments I decided to change the wording. 22 The effect is the same. Really the 23 question was of timing and I think he hit the nail on 24 the head there. Either people pay all along in terms 25 of rates or they pay in lump sums upfront. 26 Now, differences in timing are 27 important. Potential differences in the benefits 28 received from actual connections, whether they be, in 653 Frontier Economics Panel 1 general, benefits to the system as a whole or specific 2 benefits to individual customers as a whole. Those 3 types of things can exist. But, in general, all the 4 money came from somewhere and it came from rates. 5 As others have pointed out, the 6 municipalities have not put any money in. My 7 understanding is that for a long time they have been 8 prevented from putting any money in, even if they had 9 wanted to, which again it is hard to imagine that they 10 would, but they have also not taken any real money out. 11 But all the money, and I would agree 12 with Mr. Adams on this point, came from customers one 13 way or the other. It always does. 14 What is the effect of this? On to 15 page 5. 16 I expect that it has led to some 17 pretty significant cross-subsidizations in historical 18 rates. 19 My understanding -- and I have not 20 done an exhaustive study of this -- is that the 21 customer contribution policies has not been 22 particularly consistent across or within LDCs over time 23 in terms of determining what the connection charge is 24 compared to what the actual cost of connecting up a 25 customer is, and the specific versus the more general 26 benefits. All of those would have to be worked out to 27 understand the exact level of cross-subsidies that 28 existed over time. 654 Frontier Economics Panel 1 In Mr. King's phraseology, which I 2 think again was an appropriate one, this is a quagmire. 3 If you want to try to work out all the level of 4 cross-subsidies, gosh, the accounting firms in Toronto 5 are just going to be hiring like crazy. Going back 50 6 years trying to work out all the historical 7 cross-subsidies is just going to be quite a task. 8 On to page 6. 9 As Mr. Adams pointed out, there is a 10 sum of money, a difference, a lump sum potentially 11 being transferred. The restructuring of the Ontario 12 electricity sector stepping back is filled with little 13 arrows of money being shuffled backwards and forwards 14 which are written into the Act. 15 This is not uncommon. We had 16 mentioned the sort of CTC-type payments. All of these 17 involve shuffling dollars left, right, up, down, 18 centre. 19 What do we know from the policy 20 framework that is described in the White Paper and the 21 Act? And there may be conflicting objectives. I would 22 be quite surprised if there weren't conflicting 23 objectives in many ways. 24 It seems to me to point out that 25 there is a pretty clear intent of commercialization -- 26 and, as Dr. Bauer discussed, there may be some 27 differences on what that means. The people I have 28 spoken to, and not only in LDCs, seem to have a pretty 655 Frontier Economics Panel 1 clear view of what that means, and that seems to mean 2 operating on a business-like basis with a real return. 3 The LDCs seem to be specifically 4 allowed a market-based return where none existed 5 previously on money they didn't put in, which, as 6 Mr. Adams suggested, is pretty much the same, whether 7 it was contributed all in a lump sum or collected in 8 this retained operating surplus over years. 9 They are required to make payments in 10 lieu of taxes which they have not paid before in a 11 clear analogy to normal corporate taxation, and the Act 12 seems to specify that certain revenue streams are going 13 to be paying off some of the stranded debt. 14 The little diagram on the left, which 15 looks much better in the coloured version with the 16 little green arrows, showed that basically financing of 17 these LDC assets, we had a market-based return going to 18 the appointed true shareholders, the municipalities, we 19 have payments in lieu of taxes and transfer taxes on 20 the sales of LDC assets going to pay off these stranded 21 debts. 22 This seems to be how the legislative 23 framework envisions that money is going to flow. I 24 would suggest that Mr. Rodger's comments about "why 25 would you put this in here if you thought that all 26 these numbers were going to be zero", is absolutely 27 true. 28 Now on to the practicalities on 656 Frontier Economics Panel 1 slide 7. 2 Now, the first comments on this I 3 will have to preface with a kind of 4 truth-in-advertising remark that some of this is based 5 on analysis that I have not personally conducted, but 6 has been conducted partially by Roland Hermann, the CFO 7 of Hydro Mississauga and other parties I have spoken 8 to. 9 So not that I think it is untrue or 10 not that I have been able to contradict it from the 11 research I have been able to do in a short period of 12 time, but I wasn't here and he was. 13 The accounting treatment of a 14 contributed capital does not seem to have been very 15 consistent across time or between LDCs, nor does it 16 seem to have been consistently applied. 17 How the amortization was treated 18 seems to have varied between 1980, from 1981 to 1993, 19 and then again from 1994 on. So the dollar analysis 20 listed in accounts, if that fact is true, may be pretty 21 peculiarly affected. 22 Again, one would need some pretty 23 substantial accounting to go back and reconstruct that. 24 Even as importantly, not only have 25 the rules changed over time, but it doesn't seem to 26 have been very consistent across the LDCs. 27 Ontario Hydro seems to have 28 recommended an accounting treatment but didn't actually 657 Frontier Economics Panel 1 mandate it, and various LDCs seem to have gone somewhat 2 their own way at certain times or another. 3 Going back on some comments made by 4 Dr. Cronin and Mr. King yesterday or the day before, I 5 think practically it is also quite undesirable as well 6 as economically undesirable to have numerous rates of 7 return floating around. First, it seems to defy any 8 normal logic on what the opportunity costs of capital 9 are, but each LDC would have had a different ROE over 10 that time period. As Mr. King suggested, possibly for 11 regulatory reasons, it seems rather bizarre to preserve 12 all these differences going into the future. 13 Finally, as a practical issue -- and 14 again I would note this to the context of writing lots 15 of things off -- the ability to raise finance may be 16 affected by any uncertainty over future treatment of 17 return of capital. There has been a kind of a glib "Oh 18 yea, market-based return on capital. Yes, if we offer 19 that market-based return we are going to get there." 20 To try to give you a little insight 21 into what else comes into this, when an entity such as 22 a newly created commercialized LDC goes to the capital 23 markets, whether that be commercial banks, whether that 24 be the syndicated loan market, whether that be to the 25 debt markets, it is not like taking money out on your 26 credit card. These loans come with covenants and the 27 covenant packages for such loans tend to be rather 28 thick documents that prevent you from doing all sorts 658 Frontier Economics Panel 1 of things in order to protect effectively the lender's 2 interest in your cash flow. 3 The ability of a newly created 4 entity, newly commercialized entity with virtually no 5 balance sheet, no equity to raise very substantial debt 6 finance, to me seems pretty unlikely. I'm not an 7 investment banker and I don't even play one on TV, but 8 I have been involved in enough capital markets 9 transactions in the electricity sector to realize that 10 I think either the commercial banking or the syndicated 11 loan community will slam the door in your face if that 12 is the way you -- if that is the position you are in on 13 trying to raise debt financing. 14 Moving on to page 8. What is the 15 impact of this? 16 I tried to do these -- and these are 17 quite rough numbers based on the Ontario Hydro 18 financial fiscal summary from 1996, but these are 19 pretty rough numbers Rob and I were cranking out very 20 late last night just to try to give some context here. 21 According to my photocopy of this, 22 the total contributed capital -- if it is in fact the 23 right number, which it doesn't seem like it is the 24 right number -- is on the order of about $1.2 billion 25 Canadian. 26 As a very rough estimate -- and these 27 are very rough estimates -- the move to a full market 28 based return in all contributed capital would maximally 659 Frontier Economics Panel 1 increase rates by approximately, you know, $120 million 2 across the province per annum. That is if all LDCs 3 decided to move up to the full market based return from 4 day one, which they are able to do but not obligated 5 to do. 6 Again, an even rougher calculation on 7 how much does that mean, you divide something roughly 8 around the number of customers. That is probably about 9 $2.50 a month, but it would probably be substantially 10 less if there is any kind of volumetric count in it. 11 How much could it impact on the 12 dollars in the bottom part of my chart from a few 13 slides before which are going to pay off the stranded 14 debt? 15 Well, if we think that that entire 16 $1.2 billion in contributed capital and a market return 17 would attract a market value of $1.2 billion, and those 18 two are not exactly one-to-one, then that would be a 19 potential maximum impact of about $400 million on 20 payments of stranded debt from the transfer tax from 21 sale of LDCs if everyone was on. 22 There would also be an additional 23 substantial impact on stranded debt payoff from 24 payments in lieu of tax in the analogy to corporate 25 taxation on an ongoing annual basis and, from a very 26 back of the envelope number, I would suggest again that 27 is probably in the $40-$50 million range which, you 28 know, gives us an idea subject to check. 660 Frontier Economics Panel 1 We are happy to have some other 2 people run through the numbers. 3 So these are not end of the world 4 numbers, but I would also note that most of these 5 numbers are in effect fixed. Customers one way or the 6 other are going to end up paying the OH stranded debt. 7 We can have this mechanism which is at least partially 8 akin to a CTC mechanism through a taxation issue, we 9 can have lots of other mechanisms, but it comes out of 10 people's hides no matter what. 11 Conclusions on contributed capital 12 issues. Economic efficiency requires that rates be set 13 on a cost-reflective basis. I would suggest that the 14 literature on second best pricing is probably going to 15 lead you to the conclusion, if you work through it, 16 that that includes pricing of existing capital at 17 something like its value. 18 Even with the fixed assets, the value 19 of my house, we don't tend to just in the economy say, 20 "Well, gosh, it sunk so we don't really have to charge 21 anything for it any more." 22 MS LEA: I'm sorry, I missed the last 23 part of that statement. 24 MR. ADAMSON: The house is built, the 25 costs are sunk. Hopefully the house isn't sunk despite 26 the recent hurricane on the east coast. But having 27 sunk all that money, we don't have to charge for it any 28 more. 661 Frontier Economics Panel 1 The actual capital involved in 2 businesses tends to get reflected in prices. 3 The existing level of process fees is 4 probably very high. I have not numerically estimated 5 them. This is an assessment based on my understanding 6 of the tariff structures and contributed capital 7 charges of the past. It is going to be pretty much 8 impossible to back out all the past effects and to 9 return to every person in the province, many of whom 10 may be no longer around and have moved, all the money 11 that would have been due to them had we had perfect 12 cost-reflective tariffs for the last 40 years. 13 The policy framework of the Acts and 14 the White Paper clearly indicates that municipalities 15 are the beneficiaries of returns in LDC capital even 16 though they didn't put any of the money in. 17 Finally, and again in the spirit of 18 my going forward, I think if distributed capital is 19 going to be used in the future and if you want to avoid 20 even more cross-subsidy issues in the future, there 21 probably is going to have be the formation of a policy 22 which is going to try to tie these in a context of 23 customer connection charges in a slightly more clear 24 way. It is just to avoid kind of taking this problem 25 further into the future. 26 Okay, moving off that horse, which 27 seems both dead and severely beaten, and on to 28 slide 10. 662 Frontier Economics Panel 1 Everyone I'm sure will be happy to 2 get to lunch, so this will be quite quick. 3 On the base productivity factor, 4 which I think we fanned at the workshop on the second 5 and third and over the last couple days, the base 6 productivity factor assessment seems heavily based on 7 the results of the TFP study. 8 The setting of the base productivity 9 factor seems heavily influenced by the results of the 10 TFP study. 11 In my mind regulatory transparency 12 requires that important decisions are not made based on 13 information not available to other parties. That is my 14 opinion. 15 However, I recognize the problems on 16 confidentiality. That debate has already occurred. 17 I would suggest that some additional 18 TFP analysis by other parties would not prevent the 19 timely implementation of PBR. 20 There is a lot to do and substituting 21 a number into the draft handbook for the 1.25 per cent, 22 a productivity factor, those two things can go 23 concurrently, just as we have kind of -- just as the 24 actual rate of return is kind of a place holding number 25 in there. 26 As a suggestion, I would suggest 27 that -- recommend rather, that all the data be 28 available that was used for the TFP study which was in 663 Frontier Economics Panel 1 the public domain and that which the LDCs agree to 2 release under confidentiality agreements has been 3 discussed at the session. 4 That may not be all of the data that 5 was used in the TFP study. Some LDCs may never agree. 6 I suggest that that data then be excluded from the 7 study and then all the parties, including people like 8 us, including the Board's consultants, can do the TFP 9 analysis on the same dataset and see if we get the same 10 result. With that, I feel the Board can make a 11 decision with some confidence and with some 12 transparency as to the results of that analysis. 13 It's not perfect, but neither is the 14 status quo. 15 On to page 11, the efficiency 16 starting points of LDCs. 17 A mechanism with the same price cap 18 for all LDCs is inappropriate, in my mind, for a set of 19 regulated entities these have a large variation in 20 starting efficiency. 21 It is not only that some will feel a 22 little less advantaged or disadvantaged than others. 23 It is actually quite important from the customer's 24 benefit. If there is a low hanging fruit, as Mr. Adams 25 suggested, potentially maybe that should have been 26 captured for customers. There is a transfer issue. 27 While very necessarily limited, in 28 response to the inevitable questions, simple partial 664 Frontier Economics Panel 1 factor measures suggest that a potentially wide 2 variation in starting efficiencies may exist. 3 This cannot be conclusive. We don't 4 have the information. Either it is not available, and 5 some of it has not been made available to us, but a 6 quick scan through some of the information that has 7 been collected by the MEA over the years for example 8 might push you in the direction of thinking that there 9 is some potentially wide variation there. 10 We will not be able to, I suspect, 11 come to an absolutely conclusive analysis. It almost 12 is impossible to do so in these contexts. However, I 13 recommend that the Board not completely ignore a 14 problem and assume that the differences are zero 15 because they have not been measured. That also 16 contains its own fallacies. 17 If we have to fall back on simpler 18 measures, not necessarily that we will end up changing 19 the starting points and changing the productivity 20 factors, but it would probably be worthwhile for the 21 Board to have some indication, even based on what 22 analysis is possible on partial factor measures, to 23 ensure that the PBR plan will give reasonable results. 24 Moving on to page 12, I would suggest 25 that some more substantial analysis is required to 26 verify the appropriateness of the values in Table 4-1 27 if this approach is to be used -- the kind of sliding 28 scale type approach -- and that some probably fairly 665 Frontier Economics Panel 1 poor incentives and outcomes can be expected if these 2 values prove incorrect. 3 While in theory we are familiar with 4 and appreciative of many of the features of sliding 5 scale type mechanisms, and have in fact recommended 6 that it be used in terms of the regulation as BG 7 Transco in the U.K. for example, we note that it was 8 done after quite a bit more substantial quantitative 9 analysis where values for a sliding scale were put 10 forward. 11 So in theory it is good idea. 12 However, I think something is going to be needed to be 13 done to check the numbers that are in there if a 14 reasonable outcome is to be expected. 15 If there is not any kind of 16 supplemental analysis, or it simply can't be done, then 17 again in the spirit of simplicity let's not just put in 18 lots of numbers. It should probably just be removed. 19 I would offer that the consideration 20 at least of a simpler sharing mechanism in the absence 21 of a rigorous defence of the Table 4-1 values isn't in 22 order echoing some of the comments of Dr. Bauer 23 yesterday and Dr. Woo yesterday or the day before and 24 suggest that some analogies exist from other 25 jurisdictions which might be profitable to examine and 26 that it is also a bit easier to get risk symmetry with 27 respect to LDCs risks and returns often in those types 28 of mechanisms. 666 Frontier Economics Panel 1 I recognize from a regulatory 2 economics perspective the different incentive effects 3 of these different types of mechanisms. However, I 4 think if you are going to move to something a bit more 5 sophisticated like the sliding scale you need something 6 more substantial behind it. 7 Finally, last but not least, again 8 thinking about the incentives for cost savings, those 9 of you who remember the second submission will 10 recognize the picture on the left-hand side which is an 11 illustration of why a mechanism on the move to a 12 yardstick mechanism in Phase 2 can help preserve some 13 of the incentives for people to actually make cost 14 savings in Phase 1. 15 I think we all recognize that and we 16 have all been talked around -- it has been kind of 17 talked around and it has gotten kind of good vibes in 18 this discussion over the last few days. I suspect for 19 the LDCs to have any real confidence and to really 20 include it in their strategic planning process 21 something a little more solid may be required. 22 This is probably even more important 23 in the context of a relatively short price cap 24 mechanism of two and-a-half to three years. 25 It is always important in every 26 economic context to almost look to the end of the game, 27 because people look to the end of the game and then 28 back out from there where they want to be. 667 Frontier Economics Panel 1 While I think those issues have been 2 discussed in a kind of a nice "talk shop" process, to 3 really kind of incent these kinds of cost savings we 4 are probably going to have to have something more solid 5 on the table that LDCs are really going to be able to 6 build into their strategic planning framework for some 7 period of time. 8 With that, I stop. 9 MS LEA: Thank you. 10 Any questions from you, Mr. Power? 11 MR. POWER: No. No, thank you very 12 much. 13 MS LEA: Thank you. 14 Can I get an idea of how many people 15 have questions for Mr. Adamson? Five or six. 16 I think given that, then, we will 17 break for lunch and return at quarter to 2:00, please. 18 --- Luncheon recess at 1240 19 --- Upon resuming at 1345 20 MS LEA: I believe now that 21 Mr. Adamson is ready for questions. Is that correct? 22 All right. Mr. Stephenson, you 23 appear to be the first in line due to the absence of 24 others. Are you prepared to go or shall we start with 25 someone else? 26 MR. STEPHENSON: A rare honour. 27 MS LEA: There you go. 28 MR. STEPHENSON: Mr. Adamson, welcome 668 Frontier Economics Panel 1 back. 2 I would like to touch base with you 3 about a subject matter that you did not deal with 4 explicitly in your materials insofar as I am aware, 5 that dealing with the establishment and maintenance of 6 service quality and reliability standards. 7 Would you agree with me that an issue 8 which is raised intrinsically by the imposition of a 9 PBR mechanism which imposes economic efficiency 10 incentives is the risk or threat that those incentives 11 will be achieved at the expense of service quality and 12 customer reliability on the distribution system? 13 MR. ADAMSON: I have taken your point 14 but I have not quite -- what was the question part? 15 MR. STEPHENSON: Well, the question 16 is that intrinsic in -- 17 MR. ADAMSON: Oh, is that a 18 significant issue? 19 MR. STEPHENSON: -- yes, intrinsic in 20 the imposition of such an incentive is the danger that 21 the incentive will be achieved through degradation of 22 service and reliability. 23 MR. ADAMSON: Yes, absolutely. I 24 mean, one could easily hypothesize an outcome of cost 25 savings being made by effectively changing the quality 26 of the product being offered. 27 A very simple analogy might be saying 28 everyone is required to produce cars cheaper so instead 669 Frontier Economics Panel 1 of making Mercedes Benzs we make Ladas. That is not an 2 actual productivity increase. 3 So I believe any scheme at a minimum 4 of incentive-based regulation needs to include controls 5 and corrections for the quality of the product, in this 6 case distribution services being delivered to those who 7 consume them. That can be on a standards approach with 8 kind of an enforcement mechanism, which I believe was 9 discussed a bit yesterday, or perhaps more optimally 10 that kind of achievement of those quality standards 11 might be somehow built into the incentive mechanism 12 itself to the degree possible. 13 MR. STEPHENSON: In the sense that 14 the cost benefits of service is internalized into the 15 economic incentives that the scheme otherwise provides? 16 MR. ADAMSON: Yes, I think that is 17 actually quite a good way to look at it on a broad 18 economic sense if the benefits are not being maximized, 19 if the costs are being minimized despite the fact that 20 the product itself is degraded. 21 MR. STEPHENSON: In simple terms, I 22 take it that necessitates some kind of, in essence, 23 financial penalty for failure to meet whatever the 24 preferred standard is, and there may be a variety of 25 mechanisms as to how that is measured or implemented. 26 But at the end of the day that is what it amounts to. 27 MR. ADAMSON: Yes. You can go for a 28 kind of a command-in-control type approach that would 670 Frontier Economics Panel 1 say meet this standard or we do this which could be 2 sort of a pure behavioural form of regulation of the 3 issue. Or you could move to kind of an incentive or 4 penalty-based system, as you suggested, that for how 5 much everything slips some effective economic signal is 6 felt. 7 I believe there is actually 8 reasonably substantial literature about how to 9 incorporate quality differences, not only into the 10 measurement of productivity but I think incorporation 11 of these into kind of incentive-based regulatory 12 schemes. 13 I think, if I am reading your 14 question right, that is what you are kind of leading 15 towards. Clearly comparisons made without reference to 16 product quality are necessarily incomplete, and an 17 incentive regulations scheme without reference to 18 product quality is again also necessarily incomplete. 19 MR. STEPHENSON: In the sense of 20 "completeness", economists always like to talk in terms 21 of efficient outcomes and incentives to achieve optimal 22 outcomes; that the absence of that kind of mechanism 23 internal to the system could in fact result in the 24 incentives leading to non-optimal outcomes. 25 MR. ADAMSON: No. If the incentives 26 are misplaced, I think it is probably pretty clear you 27 will get a less than optimal outcome. 28 MR. STEPHENSON: Obviously, there is 671 Frontier Economics Panel 1 a level of data that is required to determine all of 2 this in terms of setting what the standards are or 3 should be and how that mechanism should work. I assume 4 that goes without saying? 5 MR. ADAMSON: Yes, absolutely. Well, 6 almost any way you are going to think about the 7 problem, that type of data collection is going to be 8 required. 9 MR. STEPHENSON: I take it you 10 haven't looked at the sufficiency of the available 11 data? 12 MR. ADAMSON: I have not looked at 13 the data collection as regarding service quality 14 standards at all. 15 MR. STEPHENSON: Assuming that the 16 Board staff proposal essentially concludes that there 17 isn't sufficient data at this point in time to go down 18 that road, would you view the systematic collection of 19 such data as being an important objective of the first 20 generation of PBR? 21 MR. ADAMSON: Yes. If we are going 22 to have it in the second, it has to be collected in the 23 first. 24 For example, I think Dr. Cronin has 25 mentioned the desire to collect some operating 26 environment data in the first round, for example, and I 27 think collection of the appropriate data -- this is in 28 effect like an operating environment-type 672 Frontier Economics Panel 1 characteristic. That is affecting the kind of cost 2 side and some of this is affecting kind of the benefits 3 side. We might try to view it on a sort of evenhanded 4 basis. Clearly, that has to be there, I think. 5 MR. STEPHENSON: There has been some 6 indication or at least a recommendation for a mid-term 7 review during the course of the first generation of 8 PBR. Would you consider this to be an important, shall 9 we say, agenda item at that point in time leading 10 towards second generation; that is, a consideration of 11 what is the information base we require, what are the 12 mechanisms that we should be looking at, that sort of 13 thing as an important agenda item during that mid-term 14 review? 15 MR. ADAMSON: Well, yes, but I 16 suggest you might actually want to extend slightly 17 beyond that. Remember the service quality indicators 18 have in some ways a stochastic nature, right? I mean, 19 its -- 20 MR. STEPHENSON: You will have to 21 help me there, Mr. Adamson. 22 MR. ADAMSON: Well, now, I am just 23 trying to lay why we may want as much of this as we can 24 collect for as long a period of time in terms of 25 designing this mechanism because clearly, you know, 26 allergies, interruptions, so on and so forth, actually 27 quite jump around due to all sorts of random events 28 from year to year. 673 Frontier Economics Panel 1 So clearly, I don't think any of us 2 would disagree that having multiple years worth of that 3 would help us not base it on one year which happens to 4 be -- for some LDC the number happens to be driven by 5 the fact of one sort of exogenous factor which no one 6 could have conceivably predicted. 7 So you might even want to consider 8 what the data collection would be right now so that we 9 don't get halfway through and get half the data in the 10 period. 11 MR. STEPHENSON: You haven't assessed 12 in terms of the proposal whether you think that is 13 sufficient for -- 14 MR. ADAMSON: I have not assessed. I 15 think I will be the first to admit I have not assessed 16 the adequacy of the data kind of collection proposal in 17 the regard of the performance standards. 18 MR. STEPHENSON: Okay. 19 MR. ADAMSON: I think it is pretty 20 clear -- I think with a bit of thought on people's 21 behalf it would be pretty clear roughly what you would 22 want to be collecting or at least a good subset of it. 23 I think I would recommend that people start thinking 24 about how to collect that. 25 MR. STEPHENSON: Let me turn to a 26 different issue. It is actually an element of this 27 issue about historic contributed capital. 28 At page 8 of your hand-out today, 674 Frontier Economics Panel 1 your sort of "back of the cigarette pack" calculation, 2 which for the purposes of today's discussion I will 3 take with whatever qualifier you want to throw on it, 4 but just using those numbers for the purposes of this 5 discussion, you talk about the $2.50 per month increase 6 and obviously that is weighted by a whole series of 7 rate design issues but -- 8 MR. ADAMSON: That is not even 9 weighted. 10 MR. STEPHENSON: -- but it is a close 11 average? 12 MR. ADAMSON: Yes. It should be 13 weighted. 14 MR. STEPHENSON: In percentage terms, 15 did you come up with any sort of even gross number as a 16 percentage of the distribution tariff, what that would 17 be? 18 MR. ADAMSON: No. I think the 19 difficulty is that this is treating a gross contributed 20 capital number for all the LDCs out of the statistical 21 summary and dividing by a rough approximate number of 22 customers. So it is not representing the fact, of 23 course, that the contributed capital percentage for 24 different LDCs seem to vary tremendously. Right? 25 So this sort of number is, this sort 26 of very simple division is based on a -- pretending it 27 was spread over everyone equally. But of course, it is 28 not going to be, or at least it doesn't sound like it 675 Frontier Economics Panel 1 would be under the proposal. So there would be 2 actually a very wide variation in that around that 3 number. 4 I can make one other quick point, 5 though, which is that it was commented on that, "Well, 6 we could have a kind of a CTC mechanism, if we didn't 7 have this", by Mr. Adams. But remember, this number, 8 whether it goes in or not, affects -- on my bottom line 9 this is going to affect the revenues of the affected 10 LDCs and therefore affects how much payment in lieu of 11 tax they are going to make. So there's a certain 12 netting there. 13 MR. STEPHENSON: Well, let me just 14 come to that, for a minute. 15 When I was thinking about this, it 16 seems to me that, from a ratepayer's perspective, if 17 their only concern is efficiency and payment down of 18 the stranded debt, the payment of the CTC is a more 19 efficient way of doing it than payment in lieu of 20 taxes. You get more bang for your buck, so to speak, 21 as a ratepayer, on CTC, because 100 cents on your 22 dollar goes to the payment down of the stranded debt; 23 whereas on the PILs, it's only by the marginal tax 24 rate. So it's, whatever, 40 cents on the dollar. 25 MR. ADAMSON: The quantities are 26 different, I agree with you. The quantities are not 27 the same. 28 The efficiency impacts -- I can't say 676 Frontier Economics Panel 1 I beg to differ but I beg to raise a different issue. 2 The efficiency impacts may be very, very much the same 3 because if you are applying it to people's electricity 4 bills on a volumetric basis, the efficiency impact is 5 fundamentally driven by the elasticity demand in 6 respect to price of electricity consumption short term 7 over long term. 8 So if CTC is also on a volumetric 9 basis and gets levied in the same way that the 10 distribution charges are, the effects may be the same. 11 It very much depends on how the charge is levied. If 12 the charge is levied on electricity consumption all 13 together, all the same, then while the efficiency 14 impacts may be relatively similar, the percentage 15 capture, I agree with you -- as you would say, this 16 captures roughly 40-something per cent, as opposed to 17 100 per cent -- 18 MR. STEPHENSON: Because the other 60 19 cents goes into the LDC's pocket -- 20 MR. ADAMSON: I'm not saying it's the 21 same as a CTC. But I'm saying that there is a 22 contribution which is, effectively, sort of CTC-like -- 23 MR. STEPHENSON: Right. 24 MR. ADAMSON: -- without being 25 exactly the same. 26 MR. STEPHENSON: Okay. And just on 27 your -- it's the second point from the bottom on this 28 page, page 8. The 400 million, in terms of the 677 Frontier Economics Panel 1 transfer tax issue -- I just wanted to make sure I 2 understood what the assumptions were there -- that's 3 assuming all of them are transferred? 4 MR. ADAMSON: Yes, that's right. 5 It's the potential maximum -- 6 MR. STEPHENSON: Right. I guess it's 7 convertibly underlying the word "maximum". 8 MR. ADAMSON: Right. 9 MR. STEPHENSON: And this is a very 10 small cigarette pack. 11 And so, the calculation includes such 12 methods of sophistication as taking 1.2 billion and 13 multiplying by 33 per cent. 14 MR. ADAMSON: Okay. 15 MR. STEPHENSON: And, obviously, 16 that's on the assumption that all of them -- 17 MR. ADAMSON: Yes. 18 MR. STEPHENSON: -- are transferred 19 to a private sector purchaser and not to OHSC? 20 MR. ADAMSON: Or to some party who 21 would be asked to pay the tax; which, of course -- 22 MR. STEPHENSON: Or to another 23 municipality, of course, who -- 24 MR. ADAMSON: Yes. So that is an 25 upper bound. 26 MR. STEPHENSON: And similarly, of 27 course, once an LDC is transferred from a municipality 28 to a private corporation, of course then they stop 678 Frontier Economics Panel 1 paying payment in lieu of taxes, as well. And so that 2 would affect your valuation on the last point, I take 3 it? 4 MR. ADAMSON: Yes, a kind of annual 5 year-to-year contribution, we may call it. 6 MR. STEPHENSON: Okay. Was it 7 possible for you to do any calculation which is, in 8 essence, the alternative to the one that you calculated 9 about your gross number of $2.50 a month, which is 10 assuming that in fact historic contributed capital is 11 treated in the way proposed in the draft handbook and 12 that the contributions toward stranded debt are not 13 collected in the manner that you propose here but 14 rather are collected through an incremental addition to 15 what the CTC would otherwise have been? Can you assist 16 us with what the impact on the CTC would be? 17 Would it be more or less than $2.50 a 18 month, on average, per customer? 19 It's a very long question. 20 MR. ADAMSON: Yes. 21 MR. STEPHENSON: To sort of get where 22 I was going to 23 MR. ADAMSON: Yes, I think so. 24 --- Pause 25 MR. ADAMSON: I see where you are 26 going. I'm trying to make sure I have got the logic 27 down. 28 --- Pause 679 Frontier Economics Panel 1 MR. ADAMSON: I mean I must admit I'm 2 rather afraid to make an estimate up here without kind 3 of working out the numbers. I don't think it's 4 difficult to do, but I really -- 5 MR. STEPHENSON: It's either smaller 6 or larger, I take it? 7 MR. ADAMSON: Yes, it's smaller or 8 larger or -- 9 MR. STEPHENSON: -- won't get more 10 specific -- 11 MR. ADAMSON: I think the principle 12 for calculating it is probably out there. But I really 13 didn't consider in any way, nor was it my intent to 14 consider, what an alternative CTC mechanism would look 15 like, or whatever. I was really taking as the 16 framework in place of what the things like the flows of 17 funds specified in the Act was. 18 So I haven't really done any kind of 19 alternative mechanism design which -- to be honest, 20 which is interesting but, I suspect, is also rather 21 outside the scope of what we are here for. I mean, 22 this seems like it has been decided to me. 23 MR. STEPHENSON: I understand that 24 point, but I guess the issue was -- I mean, you said 25 very clearly -- and there's no doubt about it -- that 26 the stranded debt, you've got to pay the piper on, one 27 way or another, and it's just a matter of how. 28 MR. ADAMSON: Yes. 680 Frontier Economics Panel 1 MR. STEPHENSON: But the issue you 2 raise here is that somehow the proposed structure will 3 adversely affect the repayment of the stranded debt, 4 and I guess the question I had was: From the ratepayer 5 perspective, you can't assist us, in fact, whether or 6 not they will be better off or worse off, in terms of 7 repayment of the stranded debt, through this treatment 8 of historic contributed capital? 9 MR. ADAMSON: Well, over time, I 10 would argue that the amounts are probably relatively 11 the same to be paid off. So that's not right. If 12 stranded debt is X, it's going to come from somewhere. 13 This is making a -- it seems to me that this mechanism 14 makes a potential contribution to that. 15 But there's also other things that, 16 without this, will have to change to hit that fixed 17 domain. 18 MR. STEPHENSON: I guess what I'm 19 getting at is that, in terms of whatever the policy 20 issues are, or economic issues are, around the 21 treatment of historical stranded debt, this issue 22 about -- sorry, historical contributed capital for 23 LDCs, whatever those issues are and whatever they play 24 out, the issue about stranded debt, frankly, nothing 25 much turns on that, does it? 26 I mean, at the end of the day the 27 ratepayers are -- they are in there and they are going 28 to pay the same amount, more or less, no matter how you 681 Frontier Economics Panel 1 set this up? 2 MR. ADAMSON: If you take this out, 3 you will have to -- if you set the contributed capital 4 to -- if you set the return to zero, say, just as a 5 number -- I realize it's not zero for everyone and has, 6 typically, been quite low numbers. If you set that 7 return to zero, I suspect that the potential transfer 8 tax payments and potential payments in lieu of tax will 9 be reduced. Right? 10 So the payment from this mechanism 11 will go down. 12 I also assume -- based on my working 13 hypothesis that this fixed amount has to get paid -- 14 that it's got to go up somewhere else. 15 My only point in making this was: 16 this is a mechanism that seems to have been built into 17 the legislation for recouping some of the money to pay 18 off such stranded debt. 19 And then, following our current 20 discussion, you know, if you don't get it here, you are 21 going to have to get it somewhere else. 22 MR. STEPHENSON: Thank you very much. 23 MS LEA: Thank you, Mr. Stephenson. 24 Mr. McKerlie? Mr. White? 25 MR. WHITE: Thank you. 26 Maybe you can help me understand the 27 cost of capital issues a little better. 28 If the cost of capital component of 682 Frontier Economics Panel 1 the IPI fluctuates with the marginal cost of long-term 2 debt, if that debt was placed at a different interest 3 rate than the then current marginal cost of long-term 4 debt, how does that impact on the effectiveness of the 5 model? 6 MR. ADAMSON: So you are saying, for 7 example -- let's take a very hypothetical very 8 simplified example. I had debt which I signed up at 9 8 per cent ten years ago, and these are not meant to 10 reflect any reality on Canadian interest rates or 11 anything. This is just an example. 12 Now, interest rates have fallen to 3 13 per cent -- again just numbers -- and input price 14 index, I think, would be trying to capture what the 15 real opportunity costs of capital, in this case debt, 16 is, right? So it varies. The situation is somewhat 17 quite analogous to people with long-term fixed 18 mortgages who find themselves in or out of the money 19 effectively on their hedge against fluctuating interest 20 rates all the time. 21 My mother had a mortgage on a house 22 in Atlanta that must have been bought in 1969 or 23 something, 1965 or something, that was at some 24 extraordinarily low interest rate for many years. By 25 the late 1970s when interest rates in the United States 26 were very high, that would have looked really, really 27 attractive. Right? 28 I mean that's just a low -- I have 683 Frontier Economics Panel 1 kind of done better than the market by buying at a low 2 price. 3 What's important for an input price 4 index -- and if I'm wrong, I'm sure Dr. Cronin will 5 correct me -- is they reflect the actual opportunity 6 costs of capital at that time. Remember, debt can get 7 refinanced at something like the market-based rate of 8 return at any time. 9 If I had an 8 per cent mortgage and 10 it's now three on my house, I'm of course saving money 11 now by refinancing, but I have been effectively over 12 time been paying more. If I had an old mortgage at a 13 very low interest rate like my mother actually did, 14 then I'm doing real well compared to current interest 15 rates. 16 Now, the nice thing about always 17 using the opportunity cost of capital in an ICI 18 structure is it says you are rewarded for doing what's 19 best. If you want to take punt on long term interest 20 rates, you can do that. If you would have locked in 21 your entire debt structure of an LDC at a current 22 interest rate and interest rates skyrocket, then you 23 will look very, very smart. If they plummet, you will 24 not look so smart. 25 The good thing about a kind of an 26 opportunity cost measure in an IPI structure from my 27 point of view is not only is it economically efficient 28 that we were big believers in opportunity costs, but it 684 Frontier Economics Panel 1 also kind of gets the incentives right towards anyone 2 engaging in a hedging strategy, which we always are 3 whenever we enter into a long-term debt instrument, 4 even if it's at a fixed price. We are effectively 5 entering into a derivative fact transaction. 6 The nice thing is it kind of puts the 7 signal back on people through the kind of comparative 8 mechanism that Mr. King and Dr. Cronin spoke of 9 yesterday to do the right thing. The right thing is, 10 you know, it almost helps prevent some Orange Counties 11 by making sure that people aren't incentivized to enter 12 the wrong type of derivative type transaction. 13 MR. WHITE: Can I ask you one more 14 question and then I think we will let it go. 15 Do you see any conflict then in the 16 use of the long-term cost of money versus, say, the 17 short-term cost of money, because the index changes on 18 what seems to me to be a relatively short term basis 19 where the component in the index is a long term 20 component, Canada long? 21 MR. ADAMSON: Well, I think in the 22 construction of a capital index, you are looking -- a 23 capital price index, sorry, I should be slightly more 24 precise. 25 You are looking for an indicator 26 which reflects to the extent possible the market cost, 27 what you think the actual input is into the utility. 28 If you believe they are tending to be 685 Frontier Economics Panel 1 financing relatively long lived assets and might be 2 looking for a long lived financing structure, then a 3 long bond rate is probably more reflective of reality 4 than a short-term six months spot, more than five years 5 or one year, or whatever other signifier you want to 6 choose. 7 The good thing is that although we 8 know there may be some problems reflecting, as 9 Dr. Cronin pointed out, between CPI and interest rates 10 or something, there is fluctuation in the shape of the 11 yield curve. I don't want to pretend that there's not, 12 but differences between short-term and long-term 13 interest rate fluctuations I would hypothesize are 14 probably -- that kind of variation is probably smaller 15 than between interest rates and maybe some other like 16 inflation measures or something. 17 You know, the yield curve normally 18 has a relatively characteristic shape so we are really 19 talking about differences in between. 20 MR. WHITE: Thank you. Hopefully 21 that's tabled. 22 MS LEA: Thank you, Mr. White. 23 Mr. Poch. No? 24 Mr. Gibbons. 25 MR. GIBBONS: Thank you. 26 Mr. Adamson, would you agree with me 27 that the Board staff's proposed price cap mechanism 28 will penalize a utility for promoting energy 686 Frontier Economics Panel 1 conservation? 2 MR. ADAMSON: Right. I'm just 3 writing down the question. 4 Well, there have been in my memory 5 numerous discussions, some here, lots of other places, 6 about the incentive properties who demand from 7 management energy conservation programs as price cap 8 versus revenue cap mechanisms. 9 Clearly, a price cap approach has 10 been chosen. If the finances in it are very reflective 11 of the incremental costs, hopefully long-run marginal 12 cost type approaches, then it should work out. I mean, 13 it should be more incentive compatible than if they're 14 not. 15 I heard the debate that went on 16 yesterday about the situation where the kind of 17 effectively short-run marginal costs on a volumetric 18 basis is very, very low, so there is a positive profit 19 incentive for a fluctuation, for an increase in demand. 20 That tends to be a benefit in a lot 21 of utilities. If you look at the accounting, it tends 22 sort of have all kinds of just volatility in terms of 23 weather related events, for example. One really hot 24 summer makes a lot of money for Georgia Power and a 25 cool one is negative. 26 I think there are potentially some 27 incentive impacts. I can't say I have really studied 28 what those are in any detail, but I agree with you 687 Frontier Economics Panel 1 there could be some incentive impacts, yes. 2 MR. GIBBONS: Given that the Act says 3 the OEB's mandate is to promote energy efficiency, to 4 the extent there are those incentive impacts that 5 discourage utilities from wanting energy efficiency, 6 would you agree that's inappropriate? 7 MR. ADAMSON: Well, I guess the 8 question is: Does it meet the requirement for 9 promoting any component of the Act, in this case 10 energy, efficiently adequately? 11 Certainly I can't think of any of 12 these systems I would say which are perfectly 13 compatible. Whether it does it adequately or not I 14 think is really effectively going to come down to a 15 subjective judgment between how you trade off all sorts 16 of theoretical and practical implementation issues. 17 I would note that one thing I think, 18 which I tried to point out in my presentation, is in 19 all these systems -- this isn't only about investment 20 demand side management systems expenditure but 21 investment in any form of capital outlay, incentives 22 that involve basically tradeoffs between capital and 23 operating expenditure, for example, are quite affected 24 by the incentive properties of the PBR plan itself and 25 extending forward to how people feel that they are 26 going to collect the benefits over time. 27 Almost stepping away from DSM and 28 just thinking about maybe even normal network 688 Frontier Economics Panel 1 investment or even a reduction in employee numbers or 2 something, it often costs money initially to make it 3 back over time. 4 So particularly even for kind of DSM 5 and energy efficiency type measures, you might want to 6 consider any question of these incentives about what 7 are the effects on those incentives of moving from a 8 Phase 1 to a Phase 2 and then eventually to a Phase 3, 9 because people have payback times on all activities 10 that they do and those may well extend beyond two and a 11 half years. 12 MR. GIBBONS: Right. 13 Thank you. Those are my questions. 14 MS LEA: Thank you, Mr. Gibbons. 15 Who else has questions? 16 MR. POCH: I still have a couple. 17 MS LEA: Mr. Poch. 18 MR. POCH: Dr. Adamson, I don't think 19 you were here this morning for Mr. Chernick's 20 testimony. 21 MR. ADAMSON: I caught the end part. 22 MR. POCH: Let me ask you just to -- 23 MR. ADAMSON: And I am Mr. Adamson, I 24 am not doctor, in deference to those who put through 25 the years in grad school. 26 MR. POCH: Okay. 27 In responding to Mr. Gibbons' 28 question about the incentive set up by price cap, I 689 Frontier Economics Panel 1 think you were suggesting that if it was all designed 2 perfectly the lost revenue, the lost end block sale, 3 should be maybe comparable to the savings in capital 4 cost achieved by installing the DSM. 5 Is that what you are saying? 6 MR. ADAMSON: There is potentially a 7 revenue impact. 8 MR. POCH: Isn't there definitely a 9 revenue impact because you are no longer selling some 10 electricity you otherwise were? 11 MR. ADAMSON: There is definitely a 12 revenue impact or probably quite likely to be a revenue 13 impact. 14 The question is: Does the LDC asset 15 have the correct incentives to actually make that 16 investment? 17 I am trying to trawl out of my 18 consciousness, because the last time I probably looked 19 at this was probably 1993 about these kinds of lost 20 revenue approaches. 21 MR. POCH: Let me simplify it for 22 you. How does the LDC fund its investment in DSM? 23 Where does that money come from? How does it get 24 repaid for them then? 25 MR. ADAMSON: Under a price cap 26 mechanism it may not get repaid. 27 MR. POCH: That would be a 28 disincentive, I take it? 690 Frontier Economics Panel 1 MR. ADAMSON: It sounds like it. 2 MR. POCH: Thank you. 3 MS LEA: Thank you, Mr. Poch. 4 Ms DeMarco. 5 MS DEMARCO: I have a few questions. 6 We have heard a lot today about low 7 hanging fruit, the fat goose and cream to skim. I have 8 a few questions regarding all of those metaphors to 9 describe what I think is a less efficient utility. 10 When comparing a utility with low 11 hanging fruit with a utility that certainly doesn't 12 have any low hanging fruit, whose shareholders stand to 13 do better generally, as a generalization, going into 14 this PBR scheme? 15 MR. ADAMSON: First off, I will 16 preface my answer to your question with a remark on the 17 comments I think all of us have made, which is whenever 18 we are talking about the low hanging fruit we should be 19 thinking not only about levels of efficiency but the 20 impact of operating environment factors. 21 There may be reasons purely outside 22 the control of management that are responsible for 23 differences in efficiency. I don't think we know what 24 those are right now. We do know that people have 25 attempted to quantify that in other places, but we 26 don't know what that is right now. 27 So whenever we are talking about low 28 hanging fruit I think we are talking about operating 691 Frontier Economics Panel 1 environment adjusted fruit. 2 MS DEMARCO: That's fine. 3 MR. ADAMSON: Perhaps this metaphor 4 is getting a bit too ripe. 5 The next question in terms of 6 really -- on an operating environment adjusted basis, 7 some really, really fat fruit -- and I'm not saying 8 necessary that any one is in here, but let's just say a 9 hypothetical LDC X had twice as many people doing every 10 task as Y. So instead of two people going in this 11 truck they had four. One had to sit in the back. 12 Instead of -- I mean, you duplicated every conceivable 13 function with twice as many people, that would be a fat 14 fruit. 15 Although the incentive should be 16 there for everyone under even a simple price cap plan, 17 they should still be incentivized to get better 18 quickly. 19 I think my comments were aimed at, as 20 you suggested, who captures that and that money can go 21 in a lot of different ways. As we have seen in the 22 England and Wales experience, for example, that various 23 people have quoted, that money I would suggest for some 24 of the companies got effectively dissipated in a 25 considerable number of ways. 26 There is the classic kind of profit 27 maximizing shareholder benefit type approach. There 28 was a great uproar at the time, as I remember because I 692 Frontier Economics Panel 1 was living there, over the salaries of management that 2 quadrupled or something and the option schemes. One 3 can potentially argue that if you are making money 4 doing what you are, you don't do that much more and 5 everybody has a little more relaxed kind of life. You 6 know, there are always agency problems for which people 7 are willing to trade increased shareholder return for a 8 golf game on Wednesday afternoon. 9 But it is not clear to me that a 10 mechanism as proposed that treats low hanging and high 11 hanging fruit operating environment suggested that 12 although it does provide incentives for all of them to 13 get better, I think really the question is: Is some 14 level of the fact that there are past operating 15 inefficiencies going to be captured for customers or 16 not. 17 MS DEMARCO: In terms of a fairness 18 basis, do you think it would be worthwhile pursuing a 19 scheme that adjusted for those who had picked the low 20 hanging fruit going into the scheme versus those that 21 had much low hanging fruit left? 22 MR. ADAMSON: Certainly I think we 23 all agree that for second generation -- or I will take 24 it that various of us agreed over the last few days 25 that that is certainly a component for Phase 2. 26 I guess the question is: What are we 27 going to do about it right now? 28 MS DEMARCO: The question is fairly 693 Frontier Economics Panel 1 theoretical. 2 MR. ADAMSON: Yes. 3 MS DEMARCO: On a fairness basis. 4 MR. ADAMSON: Fairness in terms of 5 offering everyone the same outcome for the same amount 6 of effort -- that is how you define it for management 7 effort -- yes, probably so. 8 MS DEMARCO: That's great. Thanks. 9 MS LEA: Thank you. 10 Mr. Mia, questions? 11 Mr. Rodger? No. Thank you. 12 Any other questioners? I see a 13 couple of people and we have Board staff also. 14 Mr. Adams, please go ahead. 15 MR. ADAMS: Mr. Adamson, I want to 16 turn you to page 5 of your September 14th submission. 17 --- Pause 18 MR. ADAMSON: Okay. 19 MR. ADAMS: There is a section that 20 starts on the previous page, 2.1.5, regarding 21 consistency of the OEB staff proposal on contributed 22 capital, right? This is the discussion on the 23 contributed capital subject. 24 Then, over on page 5, there is some 25 of your concerns about the contributed capital 26 treatment in the proposal. The third sentence says: 27 "Since the capital base is 28 valued at such a low level, 694 Frontier Economics Panel 1 prices will be massively 2 distorted downward which will 3 tend to encourage 4 overconsumption of electricity." 5 (As read) 6 MR. ADAMSON: Right. 7 MR. ADAMS: Do you have an estimate 8 on how much eneregy would be saved by your proposal, 9 your proposal to include contributed capital? 10 MR. ADAMSON: No, I have not made an 11 estimate. I will sketch out a chain of calculations so 12 you can make it. 13 MR. ADAMS: Sure. Please. 14 MR. ADAMSON: But I haven't done the 15 numbers. 16 Let's think about the difference in 17 an asset base, difference in the valuation of existing 18 assets and the impact on rates, which we suggest 19 varies -- I think it is suggested would vary quite 20 substantially among LDCs, first off, although I would 21 also state that there is probably some variation in the 22 existing rates of LDCs given whether or not they funded 23 a lot of their capital base with contributed capital or 24 not. 25 So there are some countervailing 26 things here. They may claim some very similar to the 27 same number. 28 If you were to take percentages, 695 Frontier Economics Panel 1 relatively small percentages, if you were to take these 2 percentages and you could look at, even on a simple 3 basis, a short-run or a long-run elasticity demand with 4 respect to price -- there are studies out there. They 5 tend to produce not always exactly the same number, 6 even for developed economies, but there are some 7 numbers out there. 8 What usually I think those numbers 9 show is that, short term, the elasticity with respect 10 to price of electricity tends to be pretty small. 11 People kind of tend to use roughly the same. 12 Over the long term, the long-term 13 elasticity demand in respect of electricity actually 14 tends to be substantially higher. So clearly we would 15 expect a long-term effect on the consumption to be 16 substantially larger than the short term. 17 MR. ADAMS: Understood. 18 But the OEB staff has proposed a 19 fixed and variable rate structure. Are you supportive 20 of the fixed, variable rate structure that they put 21 forward? 22 MR. ADAMSON: I have not done 23 sufficient analysis of their structure to say whether I 24 am agreeing with it or not, nor have I really been 25 party to all the discussions on the rate structures 26 proposed. 27 There is a fixed and variable rate 28 structure agreed, and there is in most jurisdictions. 696 Frontier Economics Panel 1 Whatever structure is imposed is 2 agreed, no matter how it is, and will involve the 3 collection of certain fixed revenues. In this case, 4 one component of that is a return on contributed 5 capital. 6 So some combination of those prices 7 will have to change, which you can decide whether 8 people are more responsive to fixed charges or variable 9 charges. One would generally suspect that probably 10 people are more responsive to the variable charges 11 because most people in Ontario, I suspect, are not 12 going to disconnect their electricity just to avoid the 13 fixed charge at any reasonable rate. 14 The principles of the calculation are 15 still the same. 16 MR. ADAMS: Let me understand. 17 If all of the contributed capital 18 rate impact goes into the fixed charge, what is the 19 impact on -- and we are agreed that customers aren't 20 going to disconnect because of that decision -- 21 MR. ADAMSON: I don't know. Maybe 22 some of them will. 23 MR. ADAMS: So your theory that 24 electricity consumption will drop relies upon consumers 25 departing the electricity system because of the rate 26 impact of contributed capital. Is that correct? 27 MR. ADAMSON: If you are going to 28 collect it all through a fixed connection charge levied 697 Frontier Economics Panel 1 upon everyone who is served by electricity, then you 2 probably have -- you are probably minimizing the delta 3 in consumption, although tradeoffs against that are 4 potentially regressive effects against small consumers, 5 which to me might seem rather significant. 6 MR. ADAMS: I'm simply trying to get 7 at your claim that this proposal encourages 8 overconsumption of electricity. 9 MR. ADAMSON: We certainly know that 10 reducing prices, one way or the other, probably -- we 11 know which way the sign goes, right? Then it comes 12 down to the art of how we actually collect the money. 13 MR. ADAMS: Thank you. No more 14 questions. 15 MS LEA: Thank you, Mr. Adams. 16 Mr. Faye? 17 MR. FAYE: Mr. Adamson, I wanted to 18 follow up on a question Mr. White asked you. It had to 19 do with short-term and long-term interest rates. 20 Did I understand you to say that you 21 didn't think short-term rates varied significantly from 22 long-term rates, or did I misunderstand that? 23 MR. ADAMSON: The question is -- and 24 we might consider this to be an empirical question: Do 25 Canadian dollar short-term interest rates fluctuate in 26 a correlated fashion with long-term interest rates? 27 Does the interest rate on a debt of term of one year 28 fluctuate in a similar fashion correlated with that on, 698 Frontier Economics Panel 1 I don't know, a 30-year debt instrument? 2 I would suspect that there is a 3 correlation there, but I can't say I have certainly 4 done the numbers for Canadian dollar debt. 5 MR. FAYE: Okay. 6 I did misunderstand. I was speaking 7 more of the magnitude. 8 You weren't suggesting that the 9 magnitude of short-term interest rates was 10 insignificantly different than long term? 11 MR. ADAMSON: Are they the same. Is 12 the interest rate on short-term and long-term debt the 13 same? Definitely not. 14 MR. FAYE: Okay. 15 MR. ADAMSON: I think we are all 16 clear in the concept of the yield curve and how to 17 date -- 18 MR. FAYE: Okay. If you could 19 clarify another thing for me. 20 You referred to Dr. Cronin's 21 assertion that the Long Bond rates are not correlated 22 with the CPI. 23 MR. ADAMSON: I believe that was a 24 point that Dr. Cronin pointed out from his study in 25 response -- or perhaps in asking questions of Dr. Woo. 26 MR. FAYE: Yes, I believe it was. 27 MR. ADAMSON: Perhaps he could offer 28 what page that was on he quoted. 699 Frontier Economics Panel 1 MR. CRONIN: It was on pages 18 and 2 19 of the staff report. 3 MR. ADAMSON: That is what I was 4 quoting, it seemed like the responses to questions from 5 yesterday. 6 MR. FAYE: Yes, I believe that is 7 correct. 8 The question I wanted to ask you on 9 that is: Does that surprise you that there is not a 10 correlation between Long Bond rates and CPI? 11 MR. ADAMSON: No, not entirely. I 12 mean one would be surprised that over very, very long 13 terms they didn't move in some sympathy. 14 For example, countries that have 15 experienced very high and prolonged inflations, such as 16 say some of the Latin American economies, one probably 17 would expect some correlation between the fact that if 18 CPI is a measure of inflation and interests, they have 19 probably both been high for a very considerably time in 20 this economy. 21 Over shorter terms, a lot of things 22 affect the -- a lot of things affect the interest rates 23 and yields on long-term debt other than current 24 inflation or even future expectations of inflations. 25 Now, I'm not a macroeconomist. I can 26 try to run through it for you, if you like, but -- 27 MR. FAYE: No, no. I was just 28 asking, generally, that this isn't a surprising 700 Frontier Economics Panel 1 outcome, that there was not -- 2 MR. ADAMSON: No. 3 MR. FAYE: -- a strong -- 4 MR. ADAMSON: There's other factors. 5 MR. FAYE: Would there be any other 6 interest rates that there would be a stronger 7 correlation with CPI on? Other than long bond rates. 8 MR. ADAMSON: You would want to do a 9 test on that. I don't know of one. But I suspect a 10 little statistical analysis would give you some 11 insight. But I certainly don't know of one. 12 MR. FAYE: Okay. That's fair. 13 Did I also understand you to explain 14 that the presence of a long bond rate, in the IPI, is 15 justifiable because the assets being financed are 16 long-lived assets? More so than a short-term rate. 17 MR. ADAMSON: Well, I guess my sense 18 is -- I'm thinking about these interest rates as a 19 measure of the opportunity cost of capital used by the 20 LDC. 21 Now, in my mind, it sort of may make 22 some sense if I hypothesize that the LDC is going to 23 attempt to enter into capital structure using long-term 24 debt to reflect those very long-lived assets. I mean, 25 that's often a pretty common capital structure 26 practice. Right? 27 People use short-term debt if you are 28 talking about, you know, building up of short-term 701 Frontier Economics Panel 1 inventory say between now and Christmas, or the 2 inventory for my toy store, and may use very long-lived 3 debt for fixed assets with very long economic lives. 4 I guess if it turned out all the 5 LDCs, for some reason, we are moving purely to kind of, 6 you know, almost like a continuous roll-over of very 7 short-term debt but almost constantly just refinancing 8 very, very short term, then I guess a question would be 9 raised about whether the IPI should reflect that 10 instead of the long-term one. I think that would be a 11 variable. 12 But, you know, if you are going to 13 use the approach, I don't see why, potentially, it 14 couldn't be reflective. 15 MR. FAYE: I was only trying to draw 16 a parallel between: if long-term rates are 17 appropriate -- long-term interests rates are an 18 appropriate factor to reflect the fact that your assets 19 are long-lived, then the converse may also be true, 20 that short-term interest rates would be more 21 appropriate to reflect the shorter life of a 22 short-lived asset. 23 MR. ADAMSON: Yes. And I would 24 suggest, from a little sort of business invite in 25 the -- from distribution utilities, that the regulated 26 entities will in effect adjust their capital structure 27 position to adjust whatever they perceive as the risks 28 imposed on it by the regulatory system. 702 Frontier Economics Panel 1 If that used very long-term interest 2 rates, then I would want something that looked as very 3 close as possible to -- if I was just purely trying to 4 minimize my risk position -- the continuous fluctuation 5 of the 30-year bond rate. If I knew they were going to 6 use month-to-month very short-term interest rates, 7 well, maybe I would want a structure of kind of 8 continuously rolling short-term debt. 9 So, it's not completely -- it's not 10 kind of completely exogenous because there's an 11 interaction between what the companies in fact will do, 12 in terms of their own capital structure. 13 MR. FAYE: I understand that. 14 Now, I wanted to ask you just a 15 couple of questions on an area that maybe hasn't been 16 explored very much. 17 We have heard Dr. Bauer, and I think 18 Dr. Cronin and various others, refer to one of the 19 desirable effects of competition and PBR as a surrogate 20 for competition to be that it stimulates technological 21 and managerial innovation in an industry that has it. 22 Do you generally agree with that 23 view? 24 MR. ADAMSON: Sorry. In the 25 introduction of performance based regulation? 26 MR. FAYE: And in its context as a 27 surrogate for competition, that one of the desirable 28 objectives is to stimulate innovation, both 703 Frontier Economics Panel 1 managerially and technologically? 2 MR. ADAMSON: Yes. 3 MR. FAYE: And would you agree that 4 that's happened in other industries, such as telecom? 5 The easiest one that comes to mind. 6 MR. ADAMSON: I'm not nearly as 7 familiar with the technology of telecoms. 8 I would suggest that that's quite 9 likely. 10 MR. FAYE: Could you comment on what 11 happens to the assets of an industry subjected to rapid 12 technological change? I'm thinking in terms of 13 obsolescence. 14 MR. ADAMSON: Quite possibly, if one 15 were to continue to think about them on an MEA, a 16 modern equivalent assets, basis or some other type of 17 measure then, clearly those asset values might drop 18 very rapidly. 19 For example -- extending a little bit 20 on the telecom example -- if I had owned a lot of 21 microwave fixed links that had been made completely 22 outdated by fibreoptic technologies, I would suspect, 23 on an MEA basis, some of those towers and equipment are 24 probably not worth very much any more. 25 MR. FAYE: And so, if the same sort 26 of thing occurs in the electrical distribution 27 industry, is there any danger of stranding some of 28 these assets, do you think? 704 Frontier Economics Panel 1 MR. ADAMSON: There's always a 2 danger -- which I think Dr. Cronin even pointed out 3 rather nicely in his paper -- that the historic costs 4 and the kind of economic value of assets really 5 diverges radically over time. Not only do asset prices 6 change but, you know, substitutability, new 7 technologies, and so on, may even sort of increase that 8 effect. 9 The question of whether those assets, 10 I guess, are going to be strandable is equivalent to 11 the question of: Is there any likelihood that the 12 regulator will, effectively, remove those from the rate 13 base. Right? 14 MR. FAYE: Yes. I think -- 15 MR. ADAMSON: I think those are 16 almost equivalent questions. 17 MR. FAYE: -- I agree with you. 18 I guess the point I was driving 19 towards was, if those assets are financed over 30 20 years, for instance, and if technological innovation 21 occurs, as has occurred in telecom, the life of assets 22 can almost disappear overnight and the utility might be 23 in the position of having a large debt on the books 24 because it's been financed over a long term and no 25 revenue to service that debt. 26 Is that a possible scenario? 27 MR. ADAMSON: Well, if you assume 28 that the rate mechanism that allows you to collect it 705 Frontier Economics Panel 1 out of whatever else you still get to do, on a 2 franchise basis, no longer exists. 3 I note that the capital markets are 4 actually pretty used to that type of risk, having just 5 finished off on a financing of a very large set of coal 6 plants in New York State. These things going to be 7 worth anything in 30 years? Who knows. Think of all 8 the risks. New technologies generation -- maybe a bit 9 more likely than on electric distributions; 10 environmental risks. You know, the capital markets are 11 pretty used to dealing with that. 12 So it's not necessarily that you 13 won't be able to finance it. I guess the question is: 14 Are you undertaking risk in signing up long-term debt 15 for those types of assets. 16 However, note that that's pretty 17 highly correlated with your whole risk of the business 18 anyway. If, somehow, no one needs wires running down 19 the street to get electricity any more and we all have 20 our micro turban that sits in the basement, you know, 21 the size of a shoe box -- under this kind of wild 22 technological hypothesis -- well, you're sunk for 23 multiple reasons, and only one of them is debt. 24 MR. FAYE: That's exactly where I was 25 going. Thank you very much. 26 If it would be prudent for the 27 utility management to anticipate that such things as 28 micro turbines and fuel cells might bypass the 706 Frontier Economics Panel 1 distribution system, would it also be prudent to 2 finance things over a much shorter period of time than 3 the traditional life span, pay the debt off before 30 4 years go by because maybe you are only going to get ten 5 years out of the asset? 6 MR. ADAMSON: That's an assessment of 7 risk which is in some ways subjective. I think again 8 one thing needs to be hopefully clear in the final 9 mechanism, that the mechanism needs to reward people 10 for making the right call on that. 11 If that's a very substantial risk 12 that can't be offlaid to the capital markets in some 13 way -- and at least some of it will be because there is 14 always some residual risk to the lender that you simply 15 won't be around in 30 years with these fancy micro 16 turbines around. I think that's where your risk 17 assessment becomes pretty much subjective, but somewhat 18 likely left where it belongs, which is with you. 19 MR. FAYE: Thank you. That's all. 20 MS LEA: Thank you, Mr. Faye. 21 Dr. Cronin, do you have questions 22 MR. CRONIN: Yes; thank you. 23 Mr. Adamson, I think over the past 24 few days there has maybe been a movement amongst a 25 number of parties converging on a sense that in many 26 cases simpler is better. We have talked about that 27 with respect to the price of capital; that is, rather 28 than having multiple prices of capital it is probably 707 Frontier Economics Panel 1 better from both the theoretical perspective -- I think 2 you and I as economists would agree with that -- as 3 well as an implementation perspective. 4 I think you talked about simplicity 5 with respect to sharing earlier. I want to just get 6 you to elaborate on your points on page 11. Here we 7 talk about setting the starting point for efficiency. 8 MS LEA: That is page 11 of Exhibit 9 D? 10 MR. CRONIN: Yes, of your handout. 11 MS LEA: Okay. 12 MR. CRONIN: Given that the Board has 13 right now in hand 48 utilities' datasets from which the 14 productivity has been dated, what would you suggest in 15 terms of your last bullet point? 16 How could one proceed from that basis 17 to, I guess, bring in some of these issues of starting 18 point differences? 19 MR. ADAMSON: Yes. Sorry. 20 MR. CRONIN: It's quite all right, 21 MR. ADAMSON: I didn't want to cut 22 you off. 23 In my mind, there's an issue and in 24 your mind there hasn't been enough information to 25 address the issue to the degree with which I think all 26 of us would like to have done. 27 My point is it seems like we have a 28 choice. We can decide whether this issue is a problem 708 Frontier Economics Panel 1 worthy of further attention or not. It does not seem 2 like we have enough information from what you and Mike 3 King have said to address it while I think we would all 4 see it as "properly". 5 I guess my comment is to say well, we 6 would not answer this problem, right? My 7 recommendation was if we don't know how to answer the 8 problem particularly right now, but we are still 9 concerned -- maybe we are still concerned. I am still 10 concerned that this significant variation exists. If 11 it exists, we can't assume it to be zero. 12 Is there anything we can do in a kind 13 of a problem identification mode which I would say is 14 allowing the Board to decide? 15 Is this small and is this something 16 that Adamson is yabbering off at the mouth about or 17 maybe is this rather substantial? 18 We can't on the basis of the 19 information right now come to a conclusion. 20 I would suggest that it may be 21 possible to look for pointers. It's like I can't tell 22 you how to drive from here to Atlanta, but I know it's 23 south and I know there's a lake between here and there 24 and I have to go west to get around the lake. 25 I don't know the answer, but I might 26 look for some pointers going south. 27 So it's my hypothesis -- and it is a 28 hypothesis -- that even looking at very simple measures 709 Frontier Economics Panel 1 which are necessarily incorrect, we don't need to 2 discuss anything. It doesn't capture all the tradeoffs 3 between capital labour and so on. 4 Would even a simple, somewhat 5 peremptory review of even very simple partial facts or 6 measures or labour productivity measures or something, 7 based on statistics or some set of statistics which in 8 my mind exist -- so we aren't talking about going back 9 and requiring lots of data and stuff, right? 10 We are talking about an assessment 11 based on numbers that are there so that the Board could 12 make this judgment which would be at least partially 13 subjective over whether this is the reason, a big 14 problem. That's really the substance of my 15 recommendation. 16 I think there are some statistics out 17 there. I have done a -- I hate to even call it 18 analysis -- a review of some of those statistics and 19 have been somewhat perplexed by some of the variations. 20 I can't explain them all. They may all be due to 21 operating environment factors which I don't understand. 22 You have got to admit that some of 23 these are listing places that I don't even know where 24 they are on the map. It's a bearing. That's all. 25 MR. CRONIN: What about the 26 issue -- we just talked about the 48 utilities that we 27 actually have at least economic data for. The other 28 utilities for whom data is much more problematic, do 710 Frontier Economics Panel 1 you have any suggestions? 2 MR. ADAMSON: I don't even know that 3 statistics cover for the same ones as your 48. Clearly 4 you probably had a much better dataset on those 48. 5 I would almost just be interested in 6 looking at: Are there variations on partial factor 7 productivity measures which, in the experience of the 8 Board or experience of people like yourself, compared 9 to efficiency analysis might be hard to explain from 10 differences in operating environment? 11 It might not be anything more 12 sophisticated than that. Then that's a basis, not a 13 perfect basis, not even a good basis -- maybe it's just 14 a slightly better than incremental than zero basis for 15 deciding, you know, yes or no, problem or not. 16 MR. CRONIN: If for whatever reason 17 it was determined that a yardstick approach was 18 impractical, and I concede that we basically both would 19 have desired to go back over phase one -- 20 MR. ADAMSON: Yes, better for phase 21 one. 22 MR. CRONIN: Do you have any 23 recommendations on how the Board should consider that? 24 MR. ADAMSON: Given the thought that 25 differences in starting efficiency were going to be a 26 big problem, let's hypothesize that there seemed to be 27 differences here which you, in your professional 28 judgment, find probably relatively difficult to explain 711 Frontier Economics Panel 1 away through the normal types of variation that we 2 might see in operating environment statistics. 3 I think then the question is: What 4 then? That's what you are asking. 5 MR. CRONIN: What would you do? 6 Would you find the plan that's currently structured 7 reasonable or would you suggest changes to it, assuming 8 for whatever reason you lodged it for the first 9 generation and it was deemed -- 10 MR. ADAMSON: What would we do in the 11 context of the plan as exists? 12 Well, then I think the Board would 13 want to consider in its judgment whether the use of the 14 uniform price cap was reasonable and whether the use of 15 the starting rate was reasonable. 16 As we have heard, there is 17 potentially quite a large variation kind of based on 18 some variation in historical rates, which may or may 19 not be cost based. We don't really know that. 20 It will certainly come down to: Does 21 it fit in the context of reasonableness in the eyes of 22 the Board, who seem to me to be left with the sole 23 authority to decide that? 24 It may be that this approach -- would 25 decide this is a bit -- this is too secondary to even 26 think about or, if not, then the Board might have at 27 least a little better information for deciding whether 28 the incorporation of the set of price caps for all is 712 Frontier Economics Panel 1 reasonable in the context of that variation. But that 2 is all it would allow us to do. 3 If the Board then, in what seems like 4 it would be its sole judgment, decided that it was not 5 reasonable, well, then I guess it would have to order a 6 remedy to be created, right. 7 But I think that is part of the 8 process which, from my understanding of how it works, 9 is left at the sole discretion of the Board. They can 10 decide it's not broke, let it go ahead. Or they can 11 decide -- and I'm not saying it is broke, I'm saying 12 there is a possibility that it is broke. 13 They can decide it is broke, and they 14 can decide it is broke but let it go ahead or they can 15 decide that it is broke and it is not going to be 16 reasonable to approve it as promulgated, go fix it, in 17 which case you get to spend a lot more time in Toronto. 18 MR. CRONIN: Actually, when you 19 mentioned that you were, I guess, a native of Atlanta I 20 should have found it somewhat funny that two people 21 from Boston, both of whom are natives of Atlanta, are 22 talking about PBR in Ontario. 23 MR. ADAMSON: In Ontario. I didn't 24 know you were from Atlanta. 25 MR. CRONIN: Those are my questions. 26 MS LEA: Any further questions for 27 Mr. Adamson? 28 Seeing none, Mr. Power, anything you 713 Frontier Economics Panel 1 have left? 2 MR. POWER: No, thank you. 3 MS LEA: Thank you. 4 Well, Mr. Adamson, thank you very 5 much for your attendance -- 6 MR. ADAMSON: Thank you. 7 MS LEA: -- for your presentation, 8 for the questions and all the advice you have given us 9 over the past few days. We appreciate it. 10 MR. ADAMSON: Thank you. 11 MS LEA: Just before we break I want 12 to talk about a couple of scheduling matters. 13 This is the last panel scheduled for 14 today and after the break what we propose to do is 15 complete the final questioning of the Board staff 16 panel. I think Mr. Adams has some questions left so we 17 will complete that. Mr. Tom Adams has some questions 18 left. 19 Then tomorrow we will be beginning 20 with the Ontario Federation of Agriculture at 9:00 21 a.m., followed by DTE/Probyn on behalf of Sault Ste. 22 Marie. Then we will hear from Mr. Gibbons from 23 Pollution Probe, if that is still agreeable to him, and 24 from Mr. White for ECMI. 25 Then the only remaining presentation 26 will be on Monday beginning at 9:00 a.m. from John Todd 27 for the Vulnerable Energy Consumers Coalition. 28 So that is how the rest of this 714 1 technical conference looks. 2 So we will take a 15 to 20-minute 3 break -- let's make it 3:25 -- and we will return for 4 Mr. Adams questions. 5 Thank you. 6 --- Upon recessing at 1504 7 --- Upon resuming at 1526 8 MS LEA: If we could reconvene that 9 would be great, please. 10 Dr. Cronin and Ms Kwik have returned 11 to the stand and we will be hearing more questions from 12 Mr. Adams. 13 Thank you. 14 RESUMED: FRANK CRONIN 15 RESUMED: JUDY KWIK 16 MR. ADAMS: I want to express my 17 appreciation to the witnesses for their patience 18 through this long and arduous process. 19 Where we left off at last day I was 20 trying to get your views on some service quality 21 indicator issues and I want to say at the outset that 22 this whole area -- I wonder if you agree with me that 23 this whole area is data intensive and will require 24 future development? 25 MS KWIK: Yes. 26 MR. CRONIN: Absolutely. 27 MR. ADAMS: The intention of my 28 question is just really not a criticism of the paper, I 715 OEB Panel 1 think the paper is an excellent starting point, but 2 just to look for areas of future development and to 3 guide the progress as PBR matures. 4 One of the concerns I have with 5 regard to the performance statistics on delivery 6 reliability is that it appears to be based on outages 7 at the customer level, but I don't see a 8 differentiation between different types of customers. 9 Am I reading correctly? 10 MS KWIK: No, you are right, it 11 doesn't differentiate. 12 MR. ADAMS: Okay. Of course there 13 are all kinds of different customers. This building 14 might be a single customer, right? 15 MS KWIK: Right. 16 MR. ADAMS: And the economic impact 17 of disconnecting this building even for a split second 18 could be very, very serious. For one thing, it might 19 impair this very helpful proceeding. 20 MS KWIK: Right. 21 MR. ADAMS: Wouldn't you agree? 22 MS KWIK: Yes. 23 MR. ADAMS: Now, what do we need to 24 get from an information point of view to be able to get 25 at performance data that adjusts for the different 26 types of customers? 27 --- Pause 28 MS KWIK: We did not discuss this at 716 OEB Panel 1 the task force and now that you have introduced it it 2 is definitely a consideration. 3 MR. ADAMS: Are you aware that at 4 least one LDC that I am aware of in Ontario has 5 historically used customer cost of interruption 6 adjusted by different types of customers, and that is 7 Scarborough Hydro, I understand. 8 Did Scarborough Hydro provide any 9 input to the task force? 10 MS KWIK: Well, we had representation 11 from Toronto Hydro. 12 MR. ADAMS: Oh, yes. 13 MS KWIK: Whether that person would 14 have been previously with Scarborough Hydro, I don't 15 know. 16 MR. ADAMS: No, I'm sorry. 17 MR. CRONIN: I'm not sure that anyone 18 offered up the same comments that you have offered up. 19 MR. ADAMS: Okay. 20 Another thing that I would like to 21 look at, from the point of view that -- there has been 22 a lot of discussion about environmental factors 23 affecting utilities of various kinds and one that jumps 24 out at me is the differential between urban and rural 25 utilities. Those utilities serving rural customers 26 have a much more challenging time keeping their 27 delivery reliability statistics up. Is that a fair 28 assessment? 717 OEB Panel 1 MS KWIK: Yes. 2 MR. ADAMS: It occurs to me that it 3 would be fairly straightforward to differentiate 4 reliability levels between urban and rural utilities 5 relative to the information difficulty of coming up 6 with estimated unsupplied energy. Is that fair? 7 MR. CRONIN: I'm not sure that the 8 distinction between urban and rural is quite as clear 9 cut. 10 For example, I know some of the 11 utilities have relatively large rural sections of 12 service territory embedded within their total service 13 territory. So, you know, we have 15 to 20 per cent of 14 it is rural, or some other magnitude of that nature. 15 You know, how do you classify the utility? 16 MR. ADAMS: I'm just saying, I'm sure 17 there are lots of grey areas but I am thinking of some 18 clear distinctions. 19 I mean, OHSC is a utility of roughly 20 similar size to Toronto Hydro in customer numbers. 21 They are the closest cohort for each other, and yet 22 they have radically different service territories. The 23 service reliability approach, all else equal, is 24 greatly beneficial to Toronto Hydro relative to OHSC 25 under this scheme. Is that right? 26 MS KWIK: I'm not sure I can make 27 that statement because, from what you were hearing, 28 Toronto Hydro has problems as well being dense. 718 OEB Panel 1 MS LEA: Has problems with what? I'm 2 sorry. 3 MS KWIK: I'm sorry? 4 MS LEA: Has trouble in the dense 5 situation that they are in. 6 MR. CRONIN: Could you explain more 7 about -- could you elaborate on your question? I'm not 8 sure why one is favoured versus the other. 9 MR. ADAMS: I am a long time aware of 10 Toronto Hydro's complaint that density makes their life 11 more difficult. 12 I am just thinking that with OHSC, it 13 has a million customers, then the amount of line -- the 14 number of poles per customer is very high. 15 MR. CRONIN: Yes. Let me just talk 16 for a minute. 17 I think density works in a similar 18 fashion at the extremes. So for very dense and for 19 very sparsely settled service territories you may see, 20 ceteris paribus, the highest cost per customer even if 21 some of the components of cost vary very much as well. 22 For example, for very dense utilities you might have a 23 line loss of 2 per cent, for very low utilities you 24 might have a line loss of 8 per cent. 25 While that component runs in one 26 direction, you would have other costs that would run in 27 a counter direction so that the dense system sparsest 28 may in fact have the highest cost. 719 OEB Panel 1 MR. ADAMS: I am particularly 2 interested in the reliability. Is there a reliability 3 impairment of density? Does density imply a 4 reliability impairment? 5 MR. CRONIN: I was speaking more to 6 costs. 7 MR. ADAMS: Yes. I take your point. 8 I wouldn't have thought that density 9 carried a reliability penalty. 10 MR. CRONIN: Of that I'm not sure. I 11 guess When you say one utility is favoured by the 12 proposal versus another with respect to this issue, I'm 13 not sure what that means. 14 MR. ADAMS: If we get to the point 15 where we have penalties in the PBR mechanism -- and we 16 are not there yet; I shouldn't have implied that in my 17 question, but if we do -- 18 MS KWIK: Okay. Can I just -- 19 MR. ADAMS: I'm sorry. Go ahead. 20 MS KWIK: I guess the problem here 21 is -- I guess we were just saying here in terms of 22 benchmarking for service reliability. Those would be 23 the same issues that we have had with trying to 24 yardstick the utilities. So there is still a long way 25 to go before we can start doing that. 26 MR. CRONIN: Right. We had exactly 27 the same discussions over the reliability issues that 28 we had over establishing the productivity targets with 720 OEB Panel 1 the same conclusion that there was not sufficient data 2 upon which to base a differential, so we basically have 3 the proposal as it is currently structured. 4 But the intent would be in the second 5 generation to make those standards more robust. 6 MR. ADAMS: Are you confident that 7 your information collection program is going to solve 8 your problem when you get there? 9 MS KWIK: I think we have had some 10 good input over the duration of the proceeding that is 11 going to help make it so. 12 Whether I am 100 per cent confident 13 that we will get there at the end of the three years; 14 is that what you are asking? 15 MR. ADAMS: Yes. I want your advice 16 on what year we are going to get there. 17 MS KWIK: Okay. Yes. 18 MR. CRONIN: I think one thing to 19 keep in mind is that, as Judy said, we have gotten a 20 lot of good feedback since the proposal went out which 21 the Board will consider. 22 The second issue is that we do have 23 planned mid-term review. It is not the thought that we 24 would have data of a long time series in the mid-term 25 review, but that the mid-term review would serve as a 26 check to see that the process is producing what it is 27 supposed to be producing. 28 MR. ADAMS: Just one question to get 721 OEB Panel 1 your feedback. 2 Our interpretation of the IPI 3 approach that you have adopted is that it looks like a 4 step in the direction of yardstick regulation. 5 MR. CRONIN: Absolutely. Yes. That 6 is the intent is to focus the utilities' attention on 7 the cost structure that is in fact representative of 8 the industry. The way that it has been structured is 9 to have the utilities, in effect, compete against each 10 other. 11 It hasn't really been picked up on 12 very much that how well a utility does on the IPI can 13 have as big an impact on its earnings as can the 14 productivity target. In fact, we see that some 15 utilities have actually done very well historically in 16 comparison to the IPI benchmark. 17 MR. ADAMS: That was our 18 interpretation. I just wanted to make sure we were -- 19 MR. CRONIN: You are absolutely 20 correct. 21 MR. ADAMS: Okay. Right on. 22 I do have a couple of questions about 23 contributions. Do be patient with me here. 24 Mr. Adamson proposed in his paper 25 that there ought to be uniform guidelines for 26 contribution-in-aid policies going forward. Where we 27 come from is a hodge-podge, right? Everybody has a 28 different contributions-in-aid policy. 722 OEB Panel 1 MS KWIK: That is what I understand. 2 MR. ADAMS: Does it make sense to 3 have a common policy for contributions in aid going 4 forward? 5 MS KWIK: I think it does. 6 MR. ADAMS: Can you give us a general 7 outline on how this would work? 8 The Market Design Committee had a 9 number of things to say about connection charges, and 10 some of that logic might apply here, but if I 11 understand correctly, contributions in aid have gone 12 beyond just connection charges. 13 Help me understand where this ought 14 to go. 15 MS KWIK: In the past it is like you 16 say, it was all over and I guess the potential for the 17 distributors to collect their contributed capital 18 through developmental charges meant even sort of less 19 regulatory oversight on it. 20 I think in the future there should be 21 at least some assurance that each utility has a 22 standard of service that applies in every case. If you 23 have a policy for contributed capital, then within your 24 utility at least you would be assured that there is a 25 consistency in standard of service for all customers. 26 MR. ADAMS: In the old days I would 27 occasionally get phone calls from people, just because 28 of where I work and where Energy Probe is located and 723 OEB Panel 1 whatnot and people seeing us in the newspaper or 2 whatever, from some guy setting up some business some 3 place, and he would be sent a bill for outrageous 4 amounts of money for contributions in aid and never 5 understood where this came from or what to do about it 6 or how it was calculated. 7 Is there going to be some kind of 8 common format so that these things are calculated on a 9 common basis, people can see it? 10 MS KWIK: I'm not working on the 11 development of those guidelines. There is another team 12 that is looking into the guidelines for system 13 expansion and they will be looking into that. 14 MR. ADAMS: Okay. 15 The starting point for this price cap 16 is current rates, right? 17 MS KWIK: Yes. 18 MR. ADAMS: Of course the utilities 19 had historically a life where they were bringing in 20 revenue from customers through current rates and also 21 business activities where they are bringing in revenue 22 from customers on a contributions-in-aid process. 23 Your PBR starting point doesn't 24 adjust for the different policies that people have had 25 historically on contributions in aid, right? 26 MS KWIK: You are referring to in the 27 past, not going forward? 28 MR. ADAMS: Yes. 724 OEB Panel 1 MS KWIK: Going forward, it is simply 2 that they won't earn a return, that if they choose to 3 take contributed capital there will not be a return 4 that would be earned on that capital component. 5 MR. ADAMS: Okay. 6 By accepting their current rate at 7 the starting point, what we have is an implicit 8 assumption that there is continuity in their 9 contribution in aid process -- the application of a 10 contributions-in-aid policy into the future, right? 11 MR. CRONIN: You lost me there. 12 MR. ADAMS: Let me see if I can make 13 it clear. Okay. Let me try it this way. A 14 hypothetical utility is currently meeting 80 per cent 15 of its cost out of rates and 20 per cent of its costs 16 out of contributions in aid. Now, the PBR formula uses 17 the rate component of the utility's business as a 18 starting point for that utility's PBR plan. 19 They have been collecting 20 contributions in aid. If they continue to grow at the 21 same rate and meet the same kinds of customer additions 22 challenges, they are going to have -- the PBR plan that 23 you put forward doesn't make any adjustment for the 24 fact that they have historically been recovering some 25 of their costs through contributions in aid. 26 MR. CRONIN: I think Ms Kwik asked 27 the gentleman from Nepean this question yesterday. Was 28 it yesterday? Yes, it was yesterday. 725 OEB Panel 1 What would they do -- 2 MS KWIK: It seems like a long time 3 ago. It's been a very long day. 4 MR. CRONIN: We have always been in 5 Toronto this week. 6 I think he said that they would have 7 to consider -- I believe he was discussing the mix of 8 borrowing versus continuing to take contributions 9 versus, I guess, the unknown choices that would be 10 offered when the capital expansion guidelines come out. 11 MR. ADAMS: I interpret that answer 12 on behalf of Nepean Hydro to be some uncertainty about 13 what exactly they are going to do about this. 14 MR. CRONIN: Right. That's partly 15 again by the fact that we don't have the guidelines 16 yet, and I assume they haven't developed some kind of 17 business plan as to how they are going to operate, in 18 part because we haven't even resolved -- well, you 19 know, we haven't resolved some of these basic issues in 20 the PBR aspect of regulation yet. 21 MR. ADAMS: Terrific. Thanks. 22 Generally speaking, would you accept that current rates 23 for the bulk of the utilities reflect their normalized 24 annual capital costs, capital budget requirements? 25 MR. CRONIN: Yes. 26 MR. ADAMS: Pardon? 27 MR. CRONIN: Yes. 28 MR. ADAMS: So under market-based 726 OEB Panel 1 rate of return, the rate base will reflect not the 2 normalized capital cost but the current year cost 3 impacts of previous year capital programs. 4 MR. CRONIN: Can I revisit that 5 answer? 6 MR. ADAMS: Please. 7 MR. CRONIN: I may have 8 misunderstood. The rates reflected the capital push of 9 their business, but only to the extent of the cost of 10 capital that was being applied to that business, so -- 11 MR. ADAMS: With no rate of return. 12 MR. CRONIN: Right. 13 MR. ADAMS: Okay. Now, for a stable 14 or growing utility, would you agree that rates would 15 tend to rise more quickly if they were to fund capital 16 in advance versus financing them over the long term? 17 MR. CRONIN: When you say funded in 18 advance, what does that mean? 19 MR. ADAMS: That is cover their 20 capital costs for long term investments on an ongoing 21 cash basis. I'm looking at the initial position. 22 I would like to withdraw my question. 23 I'm just concerned that this may not be the right forum 24 for this kind of discussion. 25 MR. CRONIN: I mean if you kind of 26 give me the general idea of where you are going, 27 maybe -- 28 MR. ADAMS: Yes, sure. Where I'm 727 OEB Panel 1 going is that we have got -- the municipal utilities 2 now have been operating on quite a different basis than 3 a normal utility. 4 MR. CRONIN: Yes. 5 MR. ADAMS: A normal utility makes 6 long term investments and they finance those 7 investments. 8 MR. CRONIN: Yes. 9 MR. ADAMS: Whereas here the 10 investments aren't financed. They are paid cash, cash 11 money. 12 MR. CRONIN: Historically. 13 MR. ADAMS: Historically, yes. 14 MR. CRONIN: But going forward -- 15 MR. ADAMS: Going forward hopefully 16 we are going to get to a normal municipal utility 17 distribution sector, right? It's very inefficient. 18 This should be an easy one. It's 19 very inefficient and it creates all kinds of 20 intergenerational cost inconsistencies by funding long 21 term investments on a cash basis. Right? 22 MR. CRONIN: Right. It has also lead 23 to the typical utility holding very large cash 24 equivalent accounts. 25 MR. ADAMS: Which in itself is 26 inefficient. 27 MR. CRONIN: Absolutely, because if 28 you consider that the typical utility had 60 per cent 728 OEB Panel 1 of its net fixed assets in cash or that cash 2 represented 60 per cent of the net fixed assets, in 3 part because of the way things were financed and for 4 abnormal situations, it really does create a 5 problematic capital structure going into the new 6 environment. 7 MR. ADAMS: I couldn't agree with you 8 more. 9 MS KWIK: To add to that, going to 10 the future, if the shareholder did not take their 11 profits and they chose to reinvest that into the 12 utility, then you could finance with cash again, but 13 they would have to be willing to give up those profits. 14 MR. CRONIN: Yes. 15 MR. ADAMS: Understood. And that's 16 their option. 17 MS KWIK: Right. 18 MR. ADAMS: Correct. Just a last 19 question. In the flurry of paper it may be here, but I 20 just haven't got it clearly in my head. Have you 21 figured out what the rate impact is going to be of the 22 market based rate of return policy proposed in the 23 handbook? 24 MS KWIK: We did work it out in terms 25 of the min/max, an average for the utilities. It's in 26 the distribution rate task force report. There's a 27 summary table in there. 28 MR. ADAMS: Is it broken out there by 729 OEB Panel 1 the net of the impact of the PIL's regime? 2 MR. CRONIN: We took taxes into 3 account in the analysis. I think the analysis was 4 probably presented with taxes included, grossed. 5 MR. ADAMS: Can you give me a back of 6 the envelope method for backing the PILs out? 7 MR. CRONIN: We could tell you an 8 exact method for doing it. We would have to attempt to 9 get some paperwork together, I think. 10 MR. ADAMS: Right on. That's great. 11 MS KWIK: Actually, I thought we had 12 put the model on the Web, the spreadsheet that you can 13 use to do that. 14 MR. ADAMS: Okay. Thanks very much. 15 Those are my questions. 16 MS LEA: Thank you very much, Mr. 17 Adams. If you do encounter difficulty in finding that 18 spreadsheet, perhaps you will let us know and we can 19 help you with that. Thank you. 20 I believe that completes the 21 questioning of the Board staff witnesses. 22 Dr. Cronin, at this time I would like 23 to thank you very much for your attendance, you and Ms 24 Kwik both. I would like to thank you for your lengthy 25 testimony over the past few days. We really appreciate 26 the efforts you have put into making this technical 27 conference a very successful one. 28 Thank you. I think that completes 730 OEB Panel 1 our business for the day, unless there's anything 2 further from anyone else. 3 Thank you. We are adjourned until 4 9:00 a.m. tomorrow morning. 5 --- Whereupon the hearing adjourned at 1553, to 6 resume on Friday, September 25, 1999 at 0900 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 731 OEB Panel 1 INDEX OF PROCEEDINGS 2 PAGE 3 4 Preliminary matters 550 5 Presentation by Toronto Hydro Panel 551 6 Questions by Mr. Cronin 557 7 Presentation by Green Energy Coalition Panel 561 8 Questions by Mr. Rodger 577 9 Questions by Mr. Gibbons 585 10 Questions by Mr. White 586 11 Questions by Mr. Cronin 594 12 Questions by Ms Kwik 604 13 Questions by Mr. Poch 606 14 Upon recessing at 1041 608 15 Upon resuming at 1103 608 16 Presentation by Energy Probe Panel 609 17 Questions by Mr. Rodger 621 18 Questions by Mr. Poch 623 19 Questions by Mr. McKerlie 627 20 Questions by Mr. White 635 21 Questions by Ms DeMarco 635 22 Questions by Ms Kwik 637 23 Questions by Mr. Cronin 638 24 Questions by Mr. Faye 642 25 Presentation by Frontier Economics Panel 645 26 Luncheon recess at 1240 667 27 Upon resuming at 1345 667 28 Questions by Mr. Stephenson 667 732 OEB Panel 1 INDEX OF PROCEEDINGS 2 PAGE 3 4 Questions by Mr. White 681 5 Questions by Mr. Gibbons 685 6 Questions by Mr. Poch 688 7 Questions by Ms DeMarco 690 8 Questions by Mr. Adams 693 9 Questions by Mr. Faye 697 10 Questions by Mr. Cronin 706 11 Upon recessing at 1504 714 12 Upon resuming at 1526 714 13 OEB Panel resumed 714 14 Questions by Mr. Adams 714 15 16 17 18 19 20 21 22 23 24 25 26 27 28 733 OEB Panel 1 EXHIBITS 2 3 NUMBER DESCRIPTION PAGE 4 5 C Document entitled 608 6 "Estimation of Incremental 7 Capacity Costs from 8 Municipal Utility to R-87-7", 9 by Peter Choynowski 10 11 D Collection of overheads 644 12 entitled "Going Forward 13 On First Generation 14 PBR - A Presentation to 15 the Ontario Energy Board" 16 17 18 19 20 21 22 23 24 25 26 27 28 734 OEB Panel 1 ERRATA/ADDENDA 2 3 RP-1999-0034 4 VOLUME 1 08/24/99 5 P. 84 L. 3 6 "authorities" S/B "utilities" 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28