170 1 RP-1999-0034 2 3 4 IN THE MATTER OF ss. 19(4), 57, 70 and 78 of the Ontario 5 Energy Board Act, 1998, S.O. 1998, c. 15, Sched. B; 6 7 8 AND IN THE MATTER OF an Ontario Energy Board 9 Staff proposed Electricity Distribution Performance 10 Based Regulation Handbook 11 12 13 B E F O R E : 14 G.A. DOMINY Presiding Member and Vice Chair 15 P. VLAHOS Member 16 S.F. ZERKER Member 17 18 19 Hearing held at: 20 2300 Yonge Street, 25th Floor, Hearing Room No. 1, 21 Toronto, Ontario on Tuesday, October 5, 1999, commencing 22 at 0903 23 24 25 ORAL PRESENTATIONS 26 27 VOLUME 2 28 171 1 APPEARANCES 2 JUDY KWIK/ Board Technical Staff 3 KEITH RITCHIE/ 4 STEPHEN MOTLUK 5 ROBERT WARREN Consumers' Association of 6 Canada 7 ROBERT POWER/ Hydro Mississauga, London 8 SEABRON ADAMSON/ Hydro, Oshawa PUC, Sarnia 9 ALEXANDER GRIEVE Hydro, St. Catharines Hydro, Whitby 10 Hydro, Petrolia PUC, St. Thomas PUC, 11 GPU Electric Inc./GPU Services Inc. 12 and Collingwood PUC, ENERConnect 13 JACK GIBBONS/ Pollution Probe 14 MURRAY KLIPPENSTEIN 15 PAUL FERGUSON/ Upper Canada Energy 16 DR. C.K. WOO/ Alliance 17 PETER FAYE/ 18 DAVID WILLS 19 MARK RODGER/ Toronto Hydro 20 RICHARD ZEBROWSKI/ 21 GINNY TAM 22 RICHARD STEPHENSON Power Workers Union 23 DAVID POCH Green Energy Coalition 24 ELISABETH DEMARCO Lindsay Hydro, Flamborough 25 ZIYAAD MIA/ Coalition of Distribution 26 DAVID FREY/ Utilities 27 NEIL SANFORD/ 28 JIM MacKENZIE 172 1 APPEARANCES (Cont'd) 2 ROGER WHITE/ ECMI 3 RICHARD GROULX 4 TOM ADAMS/ Energy Probe 5 MICHAEL HILSON 6 MAURICE TUCCI MEA 7 STEPHEN CARTWRIGHT Enbridge Consumers Gas 8 BILL HARPER Ontario Hydro Networks 9 KEVIN BELL Great Lakes Power 10 GERRY DUPONT Nepean Hydro 11 RICHARD BATTISTA Union Gas Limited 12 BRIAN McKERLIE Municipality of Chatham-Kent 13 MICHAEL JANIGAN Vulnerable Energy Consumers 14 Coalition 15 KEN ALLEN/ DTE/Probyn, 16 DARIA BABAIE/ Sault Ste. Marie 17 CHESTER BOLLING/ 18 CLIVE HEALEY 19 20 21 22 23 24 25 26 27 28 173 1 Toronto, Ontario 2 --- Upon resuming on Tuesday, October 5, 1999 3 at 0903 4 THE PRESIDING MEMBER: Good morning. 5 Is there anything before we start, Ms Kwik? 6 MS KWIK: No, Mr. Chair. 7 THE PRESIDING MEMBER: Anyone else? 8 This morning I believe it is a presentation by 9 Vulnerable Energy Consumers Coalition. 10 Is that correct, Mr. Janigan? 11 MR. JANIGAN: That is correct, Mr. Chair. 12 THE PRESIDING MEMBER: Welcome, Mr. Janigan 13 and Mr. Todd. 14 PRESENTATION 15 MR. JANIGAN: Thank you, Mr. Chair. 16 We appreciate the opportunity to attend this 17 morning, and particularly the fact that our schedules 18 were able to be met in the appointment time for this 19 matter. 20 We have prepared what I have termed a summary 21 of oral submissions which is, in effect, a roadmap of 22 where our submissions will be going this morning. 23 Certainly we are not adverse to being 24 interrupted during those submissions with questions that 25 are specifically directed to the area that we are 26 dealing with, or if it is the Board's choice to leave 27 questions to the end of the presentation that would be 28 satisfactory as well. In either case, we are happy to 174 VECC, Presentation 1 entertain questions during the course of the submission 2 and it has been organized in that way so that we can 3 entertain questions during that time. 4 THE PRESIDING MEMBER: Thank you, Mr. Janigan. 5 MR. JANIGAN: First of all, we thought it 6 useful to review the objectives of the Electricity Act, 7 which are contained in section 1 of the Electricity Act 8 and are revisited in the OEB Act as well in section 1. 9 The full list of them is set out in our 10 summary: competition and a smooth transition to 11 competition; nondiscriminatory access; consumer 12 protection for price and service; economic efficiency; 13 repayment of Ontario Hydro debt; financially viable 14 electricity industry; and energy efficiency. 15 We take particular note that it is the 16 financial viability of the industry as a whole which is 17 the legislative concern rather than industry 18 stakeholders in particular. It is our belief that 19 industry stakeholders are to be protected primarily by 20 establishment of competition and nondiscriminatory 21 access. 22 We take note of the submissions that have been 23 made, both in the written materials and in the technical 24 conference, that would seem to indicate that the 25 objectives of the Act or the purposes of the Act went 26 further than this. I may be so bold as to suggest that 27 some of these submissions have been to the effect that 28 the financial health of the individual municipal 175 VECC, Presentation 1 electric utilities is of primary concern or the Act 2 itself may be in fact the securitization of the 3 Municipal Electrical Utilities Act rather than the 4 Electricity Act and the OEB Act as set out. 5 Now, we acknowledge that there are a number of 6 barriers that are in place that are situational or 7 relate to the historic way in which the LDCs have been 8 regulated that make the job of the Board in this case 9 exceedingly difficult. The task is, in effect, at this 10 point in time, akin to attempting to thread a needle 11 with boxing gloves on, but it has to be done and we are 12 attempting to enable this process to go ahead in a way 13 which is most conducive to a result in keeping with the 14 objectives that are set out in the Electricity Act. 15 Some of these barriers we have noted. There 16 is no experience with pre-existing cost of service 17 regulation. This has, of course, the impact of having a 18 lack of informational base, which is our second point, 19 but also there has been no testing of these expenditures 20 up to this point in time. 21 It is a rare occurrence to go from essentially 22 a situation where non-profits or a state-run monopoly is 23 in existence to one in which light-handed regulation or 24 PBR takes place without passing through the stage of the 25 intense review that cost of service regulation provides. 26 But that is, in essence, what is before us. 27 The panel is well aware of the government 28 imposed timelines for implementation. To some extent 176 VECC, Presentation 1 these time lines frustrate a methodical approach or an 2 approach that may include the kind of detailed review 3 and analysis in proceedings that ordinarily take place 4 in cost of service matters. 5 The panel is well aware that there are large 6 numbers and great differences between the LDCs that are 7 before them. It makes generic regulation obviously 8 difficult. 9 As well, we are attempting to implement a PBR 10 plan during a period of rapid change. This, of course, 11 is problematic. It is not thought to be the recommended 12 way. A normal method of proceeding is, of course, to 13 wait for the industry to change and then to impose the 14 PBR on the new structure. That option is not available 15 to us. 16 Another concern is that mistakes made in the 17 implementation or the introduction of the first phase of 18 PBR may be difficult to correct in the second stage. 19 Obviously LDCs and other stakeholders will 20 make changes in either their operating structure or way 21 of doing business in conformance with the first phase of 22 PBR and the Board and intervenors may be met with the 23 argument when the second phase comes along that it would 24 be unfair at this point in time to change the rules 25 regardless of the deleterious impact of certain changes 26 introduced in the first stage. 27 As well, this is a plan that is based upon 28 obtaining a workably competitive market for electricity 177 VECC, Presentation 1 in the long run. 2 The overall success of any framework may 3 depend upon the state of consumer readiness. In other 4 words, an informed market must exist for the important 5 choices to be made between efficient and non-efficient 6 players. This may be frustrated in the event that 7 consumers are not ready. 8 We suggest, therefore, that the overall 9 approach must be one which emphasizes the consumer 10 protection and efficiency objectives of the Electricity 11 Act. In emphasizing these objectives we would suggest 12 an approach that minimizes the risks associated with 13 getting it wrong and maximizes the opportunity to fix 14 potential problems. 15 In our view, it is far preferable to attempt 16 to prevent the worst from happening rather than 17 attempting to -- well, let's put it this way: In our 18 view the situation is one in which we must prevent the 19 worst from happening rather than necessarily achieving 20 the best. We would emphasize that a strategy of risk 21 minimization, particularly consumers, is appropriate. 22 Secondly, Phase 1 must augment the 23 informational basis for LDC regulation. 24 At the moment one of the chief difficulties in 25 attempting to implement any regulatory framework 26 involves the lack of appropriate and specific 27 information for the regulation of LDCs. This period of 28 time must be a period of time during which the 178 VECC, Presentation 1 informational basis is enhanced. 2 Thirdly, the regulatory framework should be 3 accessible and transparent in its operation and 4 enforcement of standards. 5 The OEB should ensure that the performance of 6 the LDCs during this period of regulation and the 7 information collected is readily available so that the 8 consumers, the public and representatives of the public 9 can assess the performance of the LDCs under the PBR 10 framework. 11 Now, we have also made some specific 12 recommendations in the context of our paper and I am 13 going to be speaking to some of these recommendations 14 and my friend Mr. Todd particularly will be reviewing 15 those sections dealing with the financial incentives and 16 levels of productivity and proposed earnings sharing. 17 First of all, as we have suggested, that it is 18 necessary to have a phased approach. The first phase is 19 a trial period during which information will be gathered 20 in order to either refine or change the PBR framework 21 for the second phase. 22 Informational barriers such as access to 23 information which is competitively sensitive must be 24 overcome during this period of time using mechanisms 25 that may be available to the Board through 26 confidentiality agreements, access through the E.R.O., 27 summaries, development of ministry-wide standards for 28 disclosure that enable the transparent and accessible 179 VECC, Presentation 1 framework that we have referred to to exist. 2 There have been some recommendations 3 concerning extending the three-year term, that a 4 three-year term might not be long enough to allow for a 5 maximum performance during the period of operation of 6 the plan. We would suggest that the term is certainly 7 long enough for experience and is short enough, we hope, 8 to limit to consumer exposure in the event that we get 9 it wrong. 10 A contentious issue, in the context of this 11 proceeding, is, then, the exclusion of contributed 12 capital from the rate base of the LDCs. 13 We would submit that rates that are set on 14 contributed capital artificially inflate the cost base 15 and we would suggest that those arguments that support 16 the inclusion of contributed capital into the rate base 17 misapprehend the purpose of rate of return in a 18 regulated environment. 19 Rate of return compensates investors for 20 capital invested in the utility at a rate which is 21 similar to that which that investor would enjoy in a 22 low-risk industrial -- in a market situation. The 23 purpose is to allow a return that is fair and represents 24 the opportunity costs for investments that may be made 25 by that particular shareholder elsewhere. 26 This is not the circumstance, with respect to 27 contributed capital. This is capital that's been 28 contributed by the ratepayers and the entire principle 180 VECC, Presentation 1 of compensation, by way of a rate of return on this 2 capital, we believe, is mistaken. 3 We suggested that future capital maintenance 4 projects may be financed by a depreciation allowance or 5 may be dealt with by a Z-factor treatment. In this way, 6 we recognize that the importance contributed capital may 7 have in the expenses of the utility and allow a method 8 for recovery of those expenses without resorting to what 9 we think is a regulatory fiction of rate of return on 10 contributed capital. 11 The next issue we deal with in our submission 12 deals with the transitional and extraordinary event 13 costs. 14 We have suggested a tightening of the Z-factor 15 definition and, as well, a public review process to deal 16 with this particular issue and, as well, we have also 17 noted the benchmarking of transition costs may be of 18 assistance to the Board in attempting to isolate those 19 expenditures that may be excessive or not in keeping 20 with the appropriate definition. 21 We will also note that small-volume customers 22 may be in particular danger of some strategic pricing by 23 LDCs to maximize discounts to customers where there is 24 or has been established a workably competitive market 25 and increase prices to the small-volume customers; 26 whereas it's less likely that a workably competitive 27 market will be established. 28 In our view, this would move prices away from 181 VECC, Presentation 1 cost-based rates and defeat the idea of regulation to 2 promote efficiency. 3 We would, accordingly, suggest that the 4 baskets for prices must be carefully designed, 5 particularly to prevent cross-subsidy by small-volume 6 customers of costs associated with service to 7 large-volume customers. 8 Now, we have devoted a section, in our paper, 9 associated with the proposed financial incentives and 10 levels of productivity, as well as the proposed earnings 11 sharing and we have dealt with this in some detail, in 12 our paper, with an alternate proposal that's been 13 developed by John Todd. I would ask Mr. Todd if he 14 could deal with this particular section in our 15 submission, this morning. 16 THE PRESIDING MEMBER: Mr. Janigan, it may be 17 expedient if I just ask some of the questions, now, sir, 18 before Mr. Todd gets to the mic. 19 With respect to the specific recommendations 20 -- and I'm looking at your submission, this morning -- 21 on, first, the phased approach and, two, the three-year 22 term. 23 Is there anything that you would change from 24 what's in the Handbook now? Or this is just a reminder 25 for the panel that they not be frustrated by arguments 26 to the contrary? 27 MR. JANIGAN: No, there is no -- we don't have 28 any differences with that Handbook but we are attempting 182 VECC 1 to emphasis that point in particular to deal with those 2 arguments that have contended for a longer period for 3 the PBR. 4 THE PRESIDING MEMBER: Sir, on the exclusion 5 of contributed capital, I have listened to your comments 6 and perhaps you can address two issues for me. One is, 7 how does your recommendation jive or is consistent with 8 the efficiency of resource allocation if you don't price 9 capital? 10 Okay, perhaps Mr. Todd can answer that -- and 11 maybe if you wait for the end, Mr. Todd. You can either 12 wait for the end or you can answer it now. 13 MR. TODD: I can step in now, if you want, to 14 do this issue by issue. 15 THE PRESIDING MEMBER: I do have a second 16 question but I may want to give it to you, and that's 17 the consistency with gas. 18 MR. TODD: On the gas side, Enbridge and Union 19 do not earn a return on their contributed capital, as 20 you know. 21 In terms of the efficiency of capital 22 investment, I guess there's a couple of ways to -- I 23 would go back to the -- the efficiency issue, as I see 24 it, on capital, generally, is that the objective of the 25 return is to ensure that a company has access to the 26 capital markets in the future. The concept, the 27 regulatory concept, as you are well aware, tends to be 28 that you are trying to minimize rates while making a 183 VECC 1 business financially viable; and to do that, a company 2 has to be able to go to the marketplace and attract 3 capital in order to invest. So it is not a company that 4 is earning a return, it is the shareholders, the 5 investors in the company, that's earning return, and 6 they must be earning a return in their past investment 7 which, essentially, sets an expectation that the company 8 go into the marketplace and attract new investment when 9 required. That requires the shareholder to earn a 10 market return on the shareholder's investment. It does 11 not require the shareholder to earn a return, either an 12 historic -- you know, this particular return or market 13 return on the customers' investment. That translates 14 into, in effect, leverage, a higher return on the 15 shareholder's investment. And the shareholder's 16 investment, of course, takes two forms: actual dollars 17 invested and retained earnings. 18 But as long as the shareholder's total 19 investment is being a fairly treated market return, 20 that's all that they can expect in a normal regulatory 21 environment, and that leads to efficiency, in the 22 economic sense, in terms of an appropriate return that 23 enables future investment to be attracted by the 24 companies. 25 What we are suggesting is clearly the 26 precedence of the past. We are not market-oriented. 27 There was not a market return earned on the retained 28 earnings or investment, where it exists, of the 184 VECC 1 shareholder. There was some return allowed, by Ontario 2 Hydro, on contributed capital. But, in effect, there 3 were still sub-market returns being earned on the 4 shareholder's equity. 5 In the new world -- and we have to separate 6 ourselves from precedent and not get locked into doing 7 things that are inappropriate and inefficient just 8 because that was part of a small piece of the past 9 regime. 10 On a going forward basis the concept is that 11 on all of the owners' capital, including retained 12 earnings, they will be earning a full market based rate 13 of return. If they are also earning return on customer 14 contributed capital, the effective return on the owners' 15 investment is just leveraged up and made much higher 16 than the market return which certainly will benefit 17 them, a higher return, increase the value of the 18 corporation, but that is in our view windfall gain and 19 is not consistent with economic efficiency. 20 MEMBER VLAHOS: Yes, I do follow the points. 21 I must have thought about who benefits and whether they 22 share all the benefits successfully because of having to 23 price that capital now which was not priced before. 24 I guess my question was from the overall 25 economic efficiency and on a larger scale there is an 26 amount of capital that is not earning anything and 27 that's where my question went to, but I do have your 28 answers. Thank you. 185 VECC 1 MR. TODD: Perhaps just to complete your 2 question because you sort of put an extra twist on it in 3 my view. There are capital gains and capital losses on 4 past investment. It's really -- the issue is to expect 5 return on new investment and to pay a return on past 6 investment when we are in the process of adding a return 7 to the owner's own investment. I would say it's kind of 8 a way of characterizing the issue. 9 Yes, if there is some capital there there 10 should be a return, but that implies that the capital 11 was contributed by the marketplace. 12 When a customer is required to contribute 13 capital to offset the cost of something, I would suggest 14 that it is not consistent with market efficiency to have 15 the price of the product reflect investment that is the 16 customer's own money because then the customer is paying 17 twice. They are paying up front the amount of the 18 capital, plus they are paying return on that capital. 19 If you want to achieve the purity of economic 20 efficiency in terms of the pricing there should be no 21 contributed capital. The customer should be paid that 22 back and that would then convert the customer's 23 contributed capital into owner's equity and a return 24 would be earned on it. 25 MEMBER VLAHOS: Thank you. 26 Mr. Janigan, I wonder if in the fourth item, a 27 full review of transitional and extraordinary event 28 costs, you set out three factors. The first one is the 186 VECC 1 Z-factor definition tightened. Do I take it then that's 2 spelled out in the original submission by VECC? 3 MR. JANIGAN: That's correct, at the bottom of 4 page 12. 5 MEMBER VLAHOS: Give me a second please. 6 Yes, I was looking at page 30 actually, which 7 is the same thing. It's the summary. 8 In the public review process what did you have 9 in mind in terms of Z-factor? Did you envision some 10 kind of a mini-public hearing where all of us would be 11 looking at each other? 12 MR. JANIGAN: Well, likely it would take the 13 same kind of format as this proceeding. I couldn't 14 conceive of designing the PBR framework and then having 15 a full-blown proceeding dealing with the X-factor, but I 16 think a separate proceeding that dealt with this issue 17 in a format which has been commodious to the Board at 18 this point in time would be satisfactory. 19 MEMBER VLAHOS: And that would be for each 20 utility system? 21 MR. JANIGAN: No. I think it would be looking 22 at the potential Z-factors that may be available to the 23 LDCs as a whole. 24 Do you have anything further? 25 MR. TODD: If I may add, Mr. Vlahos, I think 26 that one of the reasons why we suggest a benchmarking 27 approach is to permit looking at it on a comprehensive 28 basis. It would enable the Board, rather than reviewing 187 VECC 1 everything individually in determining reasonableness, 2 actually set on an overall basis what are reasonable 3 levels of costs. It could be ranges or it could be 4 costs per customer, something like that, for particular 5 categories of Z-factors that are being accepted. 6 It would also allow the Board to review on a 7 generic basis what categories of expenses should be 8 accepted as Z-factors, as opposed to being rejected and 9 treated as part of normal costs. 10 MEMBER VLAHOS: Was it you, Mr. Todd, who 11 suggested a certain level, a fixed class per customer? 12 I believe there were two parties and I thought maybe you 13 were one of them. 14 MR. TODD: That's not the exact way I 15 characterized it, but I referred to benchmarking, so 16 there would be essentially a per customer benchmark cost 17 for accepted Z-factor categories that could be used, as 18 opposed to individual company reported numbers. 19 MEMBER VLAHOS: And how would you address the 20 differences in the development of certain things, like 21 CIS or computer systems to handle the new world? Is 22 there a way to factor that in? Someone may be at the 23 last stage and someone has not begun yet. 24 MR. TODD: You are saying in terms of some of 25 those who have already done some work versus those who 26 haven't? 27 MEMBER VLAHOS: Yes. 28 MR. TODD: There are special cases of probably 188 VECC 1 those who have made those major expenditures which are 2 probably the few large utilities. There may be, you 3 know, that they would not be claiming them, not making 4 any investments, so they would be left out. There may 5 be others who don't require them, but many of these 6 expenditures are probably going to be done on an 7 industry basis, like a CIS. We can hope anyway that 8 every company is not going to be developing their own 9 CIS from scratch, but rather they will be going to the 10 marketplace and obtaining services. 11 You have seen the arrangements with Union Gas 12 with Enlogics where it's a transaction-based charge. 13 Enbridge is going in a similar direction and companies 14 will go in that direction and benchmarking is probably 15 appropriate, which will be another incentive to ensuring 16 that they are structuring their systems on an efficient 17 basis with either mergers or co-operative efforts and so 18 on in order to do these things efficiently. 19 It is important again to recognize the whole 20 concept of this first generation PBR is saying we can't 21 be precise, we can't get it right and so we are going to 22 have to use a few simplified rules of thumb and this one 23 size fits all cannot possibly cater to each utility 24 specifically. 25 I am just suggesting it's consistent with that 26 to approve Z-factors on a sort of "one size fits all" 27 basis that says let's take a benchmark and for the 28 duration of the first generation PBR companies can live 189 VECC 1 with that. Come the second generation they will 2 probably come in and try to justify a new starting point 3 for second generation. 4 MEMBER VLAHOS: And you don't see a problem, 5 Mr. Todd, if we follow some kind of a benchmark and just 6 for the sake of discussion $10 per customer is an easy 7 number and then you can have a situation where you are 8 talking about $10,000 for a small system, a thousand 9 customers, versus $10 million for a large system. Are 10 there no economies of scale to be recognized here 11 somewhere? 12 MR. TODD: Part of this broad Energy 13 Competition Act where it is taking us is to expect all 14 the utilities to find efficient ways to provide what 15 they must to the customers. Whether they determine that 16 can be done by a merger, whether that can be done by a 17 co-operative setting for a billing system for a hundred 18 of them, staying individual and in fact contracting out 19 to a common provider, I don't think that's unreasonable. 20 What it is doing is saying find a way to do it that's 21 efficient relative to others in the marketplace. 22 There may be some minor differences that a 23 large number of small utilities may not be able to get 24 it for quite the same price as the single large utility, 25 but if we try to get that precise we are working against 26 what is a very clear concept in this PBR Handbook which 27 says we don't have the data, we don't have the ability 28 to treat every company separately, so we are going to 190 VECC 1 use a standardized approach. 2 I think that's practical and necessary for 3 first generation PBR. I am saying it is consistent to 4 do that with the Z-factors or you are going to be into a 5 morass of arguments over why every company is different. 6 The big ones will say they have greater 7 demands and they should be higher. The smaller ones 8 will be saying we have, you know, smaller economies of 9 scale, but remember the underlying principle is 10 incentives. 11 In the absence of a benchmarking approach to 12 Z-factors you are essentially saying, you know, whatever 13 you spend you can pass through and there is no incentive 14 to be efficient in the implementation of Z-factor items. 15 MEMBER VLAHOS: Thank you. My last question, 16 Mr. Janigan. 17 You talk about the limitations on permitted 18 price and flexibility and I guess your concern is, as I 19 read your comments, that cross-subsidy always goes in 20 one direction. 21 Is this your fear that it will go in one 22 direction in this case? Are we talking about Ramsey 23 pricing? 24 MR. JANIGAN: Yes. I think that is 25 essentially our concern in the circumstance. 26 The experience with other markets that have -- 27 other utility markets that have involved a transition of 28 competition, it seems as if the small volume market is 191 VECC 1 the last market to become workably competitive or to 2 have market forces influence the price. We are 3 concerned that during that transition that LDCs may, in 4 fact, strategically price so that they remain or 5 maintain their market share in the large volume market 6 and, in effect, use the small volume customer's rates to 7 finance those efforts. 8 MEMBER VLAHOS: This is irrespective of who is 9 the owner, whether there is a private owner or a 10 municipality where different considerations may kick in. 11 Are you thinking of the end state model where 12 there is a commercial footing, it doesn't matter who 13 owns the utility? 14 MR. TODD: It's the market incentive and 15 market incentives can apply to any company. 16 In a privately owned corporation there is a 17 shareholder that essentially will toss out the owners if 18 they don't follow those market incentives and take the 19 best advantage of the opportunities. 20 In a municipally-owned utility, the owners may 21 not, but the individual municipalities, we have seen 22 already, are taking different approaches. Some are 23 viewing this as a chance to make some money on 24 electricity and they will behave and expect their 25 municipal electrics to behave exactly like a private 26 sector corporation would, go out and maximize profit. 27 You know, others may choose a different strategy. But 28 the concern is there even with the municipally owned, 192 VECC 1 although we recognize there will be a diversity of 2 policy strategies across them. 3 MEMBER VLAHOS: Thank you, gentlemen. 4 Thank you, Mr. Chairman. 5 THE PRESIDING MEMBER: Dr. Zerker. 6 MEMBER ZERKER: To follow up on the -- good 7 morning, Mr. Janigan, Mr. Todd. 8 I just want to follow up on the question of 9 pricing flexibility and your concern about cross- 10 subsidization. Does the handbook's 5 per cent 11 limitation of shifting from one basket to another -- 12 does that not seem sufficient protection enough? 13 MR. TODD: The presumption in the handbook is 14 that we are starting with cost-based rates. The reason 15 for that is that there has not been a policy of not 16 having cost-based rates. While there is insufficient 17 data to support it, the objective I think would be that 18 if we in fact had cost of service studies by rate class 19 we would be looking at moving rates more in line with 20 cost-based rates. The principle is cost-based rates for 21 a monopoly. 22 Our assumption is that where there is pricing 23 flexibility, the market incentive is that it will be 24 used to the maximum to shift costs from less captive 25 customers to more captive customers. And it is fairly 26 clear that the larger the volume the customer the less 27 captive they are, the more able they are to go to the 28 utility and say, "If you don't give us a break we will 193 VECC 1 seek ways to bypass the system, we will relocate." 2 That has been the experience of Ontario Hydro 3 with its competitive rates. Residential customers do 4 not go to Ontario Hydro and say, "We will relocate in 5 Georgia unless you give us a special rate", but large 6 customers do. Therefore it is the expectation that 7 whatever pricing flexibility is there will tend to be 8 used possibly to its maximum to shift costs from one 9 class of customers to another. 10 MEMBER ZERKER: I understand that. 11 My question is: Under the price cap scheme is 12 there as great a concern of yours as it would have been 13 had there not been a limitation on that kind of 14 cross-subsidization or shifting of -- 15 MR. TODD: If there were no 5 per cent limit 16 there would be greater concern. 17 MEMBER ZERKER: Yes. But the 5 per cent limit 18 is not reassurance enough, is it? I'm thinking in terms 19 of what the price cap scheme in the handbook, what 20 interest it serves and whether or not you are telling us 21 that that is not sufficient to protect your concern. 22 MR. TODD: The assumption is, the expectation 23 would be, that with a 5 per cent limit that after three 24 years residential rates in many areas will be 15 per 25 cent above cost-based rates and large volume rates be 26 reduced comparably. And if, in fact, we are starting at 27 cost-based rates, that is inappropriate and it will be 28 necessary, once we have the cost of service studies, to 194 VECC 1 then correct that cumulative 15 per cent shift in the 2 recovery of costs. 3 So, no, it is not a reassurance. What we are 4 saying is that there should be no shifting until the 5 cost of service studies have been completed, and find 6 out what direction in fact a cost recovery should be 7 shifted, maybe that there is over-recovery from 8 residential customers already and we should be shifting 9 in the other direction. 10 But, you know, why in this rate handbook are 11 we inviting a shifting of costs when the principle is 12 cost-based rates and we have no evidence to say they are 13 out of whack right now? 14 MEMBER ZERKER: Can I turn to Ms Kwik. 15 Under the first phase, could there be -- I 16 just want to clarify this -- could there be a 15 per 17 cent shift during the first phase? 18 MS KWIK: It's actually at the rate adjustment 19 for the second year and the third year. That is just 20 the opportunity to do that flexibility, so it wouldn't 21 be accumulative of 15. 22 It's also 5 per cent of the rate change, which 23 is not the same as I guess 5 per cent of the entire 24 rate. 25 MEMBER ZERKER: Thank you for the 26 clarification there. 27 Mr. Janigan, I'm looking at the transition and 28 extraordinary event cost in the Z-factor. I suspect or 195 VECC 1 I assume that you are talking about benchmarking in 2 relation to transition costs rather than through 3 extraordinary events cost. Is that correct? I mean, 4 can you benchmark an earthquake? That is the sort of 5 thing that I am -- I mean, I'm not being facetious here 6 because we have had a lot of earthquakes, unfortunately, 7 around the world lately. 8 But I'm asking you to distinguish between 9 transition costs and extraordinary events, or is there a 10 distinction? 11 MR. JANIGAN: Well, there may be 12 circumstances. For example, a good example of an 13 extraordinary event which cuts across all utilities may 14 be Y2K costs, for example. In that circumstance we 15 hopefully will not experience another Y2K at least until 16 the next millennium. 17 MEMBER ZERKER: Well, I won't be here to worry 18 about it. 19 MR. JANIGAN: But in that circumstance, even 20 though it is an extraordinary cost, benchmarking may be 21 an appropriate approach to looking at whether the costs 22 are reasonable. 23 MR. TODD: Just to clarify, when we refer to 24 the benchmark, we are not saying that that would 25 necessary apply to all utilities. It would apply to all 26 utilities applying for that Z-factor. 27 So, for example, say there was an ice storm 28 that affected one part of the province, those who are 196 VECC 1 affected may come in and ask for an adjustment to the 2 Z-factor and the reference or benchmark rate would be 3 applied to them in terms of costs. 4 In addition, of course any company at any time 5 could ask for an exemption from the rule if there were 6 some extraordinary factor that required special 7 treatment. I would think the Board would be reluctant 8 to do that because then it would require either just a 9 blanket acceptance of what is being submitted or it 10 would require a case review to determine whether in fact 11 the costs that are submitted were prudently incurred. 12 MEMBER ZERKER: It sounds to me that when you 13 introduced these regional conditions that you are also 14 asking for some element of a case-by-case review. 15 There are always people on the edge of a 16 storm, for example, who may have a claim or may not have 17 a claim depending upon the case we make. So we get back 18 to the fact that benchmarking isn't uniformly adaptable, 19 even under those circumstances, as you suggested earlier 20 to Mr. Vlahos. 21 MR. TODD: That is absolutely true of the 22 entire price capping mechanism. Taking your comment, 23 which is absolutely true, to the logical stream, we 24 should be doing individual company review of all costs 25 because every company is different. We could not do a 26 one-size-fits-all performance-based regulation regime. 27 What we are saying is that we are accepting 28 the premise of the PBR Rate Handbook that says we can't 197 VECC 1 do that. Therefore, we have to use a streamlined 2 incentive-based approach. 3 The thesis being put forward in our 4 submissions is that the same principle should apply to 5 Z-factors. They should be incentive-based and 6 standardized. 7 MEMBER ZERKER: Thank you for that. 8 Could I ask you, on behalf of the Board, how 9 one walks between the positions that are put forward on 10 contributed capital, which claims that in fact they are 11 not double counting and your position that they are? 12 I know you have heard all the arguments, so I 13 am not going to repeat them. They are such opposing 14 points of view that I would appreciate if you would 15 somehow try and sort things out for us. 16 MR. TODD: I noticed you used the words "walk 17 between". It is very common regulatory policy where 18 parties are pushing in opposite directions to say well, 19 some middle ground is correct because there is, shall we 20 say, truth to both sides. 21 I find it difficult to say walk between in 22 this particular case. Either contributed capital should 23 earn a return for the owner, because somehow it is 24 reflective of the owner's investment; or, in my view, it 25 has to be recognized that it is the customer's money 26 that has been contributed and whatever Ontario Hydro did 27 in the past is irrelevant. It is money from the 28 customer, and therefore the owner should not get a 198 VECC 1 return on it. 2 In my view, this is an issue of principle, and 3 the Board must make a decision between the opposing 4 principle points of view; decide who they think is 5 viewing the issue more correctly. It ends up being a 6 winner take all decision. 7 If you believe that the municipal electrics 8 who are arguing that they should get a return on it are 9 right, then you should give them fully what they are 10 asking for. If you believe that in fact it is the 11 customer's money -- and I am biasing the way I am 12 comment on it here. If it is the customer's money and 13 the customer should not be paying a return on it, which 14 is our submission, then there should be no return earned 15 on it. 16 While yes, you can split the difference and 17 allow a lesser return, I would suggest that you should 18 actually confront the conceptual question and make a 19 policy decision as to who is right and who is wrong. 20 MR. JANIGAN: Let me just interject on this. 21 I would also submit that it is the Board's 22 decision to make on principle, and the Board should 23 reject the arguments that have been put forward in this 24 proceeding to the effect that Part 11 of the Electricity 25 Act has empowered the municipalities to in effect set 26 their own rate base in this matter, and the Board 27 cannot, in the context of looking at this issue, 28 interfere with the decision that was made in the course 199 VECC 1 of a transfer by-law. 2 I just do not see the support in the Act for 3 that interpretation that would give the municipal 4 transfer by-law precedence over a decision made with 5 respect to the methodology for setting rates that are 6 set out in the Act to the OEB. 7 In our respectful decision, this is a decision 8 for the Board and for the Board to make alone. 9 MEMBER VLAHOS: Dr. Zerker, perhaps I could 10 follow up with one question. 11 You mention about owners and ratepayers, and I 12 guess there is no confusion in this case that the 13 ratepayers may be the owners, at least in large part? 14 MR. TODD: Yes. I mean, the ratepayer in 15 general is going to be the taxpayer. So it is one 16 pocket or the other. 17 But I think it is more than one pocket or the 18 other, because if the return is allowed on the 19 customer's contributed capital, that will turn into a 20 lifetime of paying return on it. There may well be a 21 buyer where that return is capitalized into the purchase 22 price of the utility, and a big chunk of cash is going 23 to flow to the utility. 24 So it ends up that the municipality may end up 25 with a big chunk of money today, and its customers will 26 end up paying for that money for the rest of their 27 lives, because they will be paying a return on it to the 28 new owner, the corporate owner. They will end up with 200 VECC 1 an arena with the mayor's name on it that they will be 2 paying for for the rest of their lives. 3 If that is what this is all about, I have a 4 concern. 5 We are turning contributed capital for the 6 electrical system into a chunk of money for the 7 municipality that it can use any way it wants. 8 Municipalities don't have debt. Once they sell off the 9 electrical utility, they can't use that money to 10 reinvest into the electrical system. So they clearly 11 have to use that equity, which has been capitalized, and 12 return to the municipality to invest in some other way 13 -- not into electrical system, by definition. 14 It seems to me that that ends up being an 15 inappropriate use of the contributed capital, because it 16 is not for the electrical system. 17 MEMBER VLAHOS: Thank you. 18 THE PRESIDING MEMBER: I am going to follow up 19 on that question, as well. 20 In terms of the source of funds which 21 utilities have used to construct their systems, it 22 appears to me that there have been three. One is debt; 23 some of them have debt. One is funds retained from the 24 rates, surpluses that have resulted from the rates. And 25 the third is by requiring a contribution, development 26 charges, or whatever you call it. 27 The utilities have different compositions of 28 what it is. 201 VECC 1 I am interested in your position as to whether 2 you are saying they shouldn't earn a return on anything 3 other than the debt, since the argument has been made 4 that the source of the contributed capital and the 5 source of the surplus in rates are both from the same 6 source: the ratepayer. 7 MR. TODD: And I guess that's what I view as, 8 in a sense, a compromise situation as well. 9 Where we are coming from is that retained 10 earnings be treated as equity, the owner's equity, and 11 earn the full market-based rate of return. And explicit 12 contributed capital, which typically is from development 13 charges in many locations, a separate lump sum charge, 14 not earn a return. 15 That money is kind of like buying an ownership 16 or paying for it oneself. 17 In the new world, remember one of the concepts 18 for contributed capital is in effect the customer could 19 make the decision as to who builds it and in effect, 20 rather than contributing capital, could just build it, 21 build part of the extension themselves; not only pay for 22 it through the utility, but actually do it. 23 Clearly, if that had been done, rather than 24 contributing money, contributed part of the facilities, 25 and it is just being operated by the municipal electric 26 utility, I don't think this would even be an issue. It 27 is a vehicle, this vehicle that has been used to have 28 the customer, or developer in many cases, provide the 202 VECC 1 facilities. 2 THE PRESIDING MEMBER: Thank you, Mr. Todd. 3 I think we had better move on. Please carry 4 on. 5 MR. TODD: I was going to comment on the 6 earnings sharing issue. Particularly given the time I 7 sort of moved to the highlight. 8 You may have in front of you the original 9 submission, my comments on behalf of VECC, and in it 10 there are two tables that are worth looking at I think, 11 Table A which appears on page 15 and Table B appearing 12 on page 21. 13 The main thrust and purpose of these tables is 14 to provide a comparison for a fairly typical LDC with 15 35 per cent of its total revenue in a corporatized 16 structure being used as a return on equity. What I have 17 looked at is the actual productivity that would have to 18 be earned or have to be realized by the company to make 19 it worth opting for a higher productivity factor. 20 Now, taking this illustrative utility, what 21 this shows in running through the calculations -- and 22 there is an appendix which discusses the methodology -- 23 we see that for example for a utility under the Rate 24 Handbook proposal to opt for a productivity factor of 25 2 per cent it would have to actually achieve a minimum 26 productivity level of 10.6 per cent. If they did not 27 earn at least 10.6 per cent they would be better off 28 choosing 1.75 per cent as their target, i.e., their 203 VECC 1 ultimate return on equity would be higher if they opted 2 for the lower productivity return. 3 What I am suggesting is that when you actually 4 run through the numbers -- and it is going to vary 5 depending on the specific cases of individual utilities, 6 but this is the middle of the road -- the kind of 7 productivity performance that would have to be 8 accomplished in order for the companies, for the 9 municipals to choose higher productivity levels, are 10 unrealistic. Therefore, I am suggesting that under that 11 structure, except for perhaps some very special cases of 12 utilities, there will be very little, if any, incentive 13 to go beyond very low productivity factors of 1.25 or 14 maybe 1.5 at the most. 15 In addition, when we run through and look at 16 the sharing of the total productivity gains between the 17 LDC and the customers, we see 80 to 90 per cent of the 18 productivity gains going to the LDC with a relatively 19 small proportion going to the customer. 20 Now, if the purpose of this sharing mechanism 21 is strictly to provide an incentive, i.e., we know we 22 have a good sense of what productivity is achievable and 23 we are rewarding companies for truly exceptional 24 performance, then it may be realistic to design a system 25 that rewards the company fairly highly for that 26 extraordinary performance. 27 But I am suggesting that a primary reason for 28 sharing in this case is because we are uncertain of what 204 VECC 1 the appropriate productivity target should be and we may 2 well be underestimating the appropriate productivity 3 target, not only across the industry generally but 4 certainly on a case-by-case basis where there will be 5 large variances. 6 The purpose of sharing should be a matter of 7 risk reduction, risk to the customer that you have 8 underestimated and that too much of the reward is going 9 to go to the company and minimizing the risk to the 10 utility that the productivity may be high. Therefore, 11 from that concept of sharing it should be a more 12 equitable sharing, more like 50/50. 13 The alternative approach that I suggest, 14 rather than setting an ROE ceiling which varies with the 15 productivity factor, adjust the actual sharing of the 16 earnings based on the productivity factor that is 17 chosen. 18 Now, we see here -- and in that table there is 19 actually a number left out, if you have it in front of 20 you, and I mentioned that in the technical conference. 21 Table B, the final line or selection "Z" should read 22 6.5 per cent, not .5. 23 But we see here that in order for a company to 24 choose a productivity factor of 2.0 you would only have 25 to expect to actually realize a productivity gain of 26 3.5 per cent. That is much more realistic to achieve. 27 It is much more likely, therefore, that a utility will 28 actually opt for that higher productivity factor. In 205 VECC 1 fact, they could go as high as a 3 per cent productivity 2 factor under this scenario, while their minimum -- their 3 realized productivity will only be 6.5 per cent. 4 Remember, what you have to do is you have to 5 substantially beat the target in order to be worth 6 choosing the target, because the target is setting a 7 higher bar that you must jump over and if you don't 8 clear the bar by a substantial portion you are better 9 off taking the lower productivity target and earning a 10 bigger share on the amount below the target. 11 In addition, it shows that the sharing is much 12 more equitable. For a low productivity factor a large 13 portion of the dominant share goes to the customer and 14 as the utility takes higher and higher productivity 15 levels that sharing shifts in favour of the utility. If 16 they go to a 3 per cent productivity factor the share to 17 the LDC goes up to almost two-thirds. 18 Again, I think that this is appropriate. With 19 movement in the productivity target there is a shifting 20 more and more in favour of the utility. Lower 21 productivity -- achieved productivity is necessary. 22 That is going to create a higher incentive for the 23 utilities to choose a higher target productivity, which 24 sets a threshold that they will then work toward. 25 Experience in other jurisdictions, like in 26 British Columbia with West Kootenay Power and BC Gas, 27 when you look at performance it is a strong indicator 28 that the target productivity level becomes an objective 206 VECC 1 for management of the company and what they realize was 2 what the target is. 3 It's a management by objective. That is their 4 objective, that is what they work toward and that is 5 what keeps their owners happy. Therefore, I think that 6 it is very important that we create a realistic and 7 strong incentive for a company to choose a higher target 8 because probably what it will do is achieve whatever 9 target it chooses plus a little bit. If it chooses two 10 it will get about two, if it chooses three it will get 11 about three. 12 That is the main thrust of that section of the 13 comments. 14 I think this alternative approach is much more 15 workable, will achieve -- will get the utilities to 16 choose higher productivity levels and will result in 17 more equitable sharing. 18 MR. JANIGAN: Thank you. 19 Let's continue on with our summary. 20 The next section where we have made specific 21 recommendations is in the area of performance standards 22 and penalties. 23 We have suggested that customer satisfaction 24 surveys should be included as part of the framework 25 associated with performance standards, that the results 26 of those surveys could provide feedback both for the 27 companies, for the Board, for interested parties and may 28 add to the information that is available, particularly 207 VECC 1 in crafting the second generation PBR. 2 Obviously we believe that public reporting of 3 the performance standards and the ability of the LDCs to 4 meet the performance standards will be required both as 5 a disciplinary feature and as well to inform the public 6 and the representatives of the public particularly in 7 dealing with protective measures that may be necessary 8 in the second phase of PBR. 9 We have proposed some specific performance 10 standards. I don't propose to revisit them in our 11 summary. They include matters such as emergency 12 response and telephone accessibility and dealing with 13 the momentary outages. 14 Importantly, we believe, penalties for failure 15 to meet performance standards should be incorporated in 16 any plan. 17 The experience of public utilities in moving 18 to a more competitive framework is somewhat instructive 19 with respect to service quality, particularly in the 20 United States in the large telecommunications companies. 21 They have been and continue to experience frequent 22 problems with service quality. We may run into the same 23 problem that we fear with respect to pricing, that there 24 may well be a decline in service quality associated with 25 residential or low-volume customers and efforts made to 26 maintain the high-volume customers with respect to 27 service quality or at the expense on that sector dealing 28 with residential or low-volume customers. 208 VECC 1 With respect to public education, we note that 2 some of the submissions that have been made in the 3 course of this proceeding are somewhat alarming for 4 consumer representatives as to the kinds of percentage 5 increases in distribution rates that may be expected 6 with or without the inclusion of contributed capital. 7 We posed a question whether or not there might be 8 sticker shock. Certainly, as the Board is aware, the 9 method of presentation of entire reform of the energy 10 industry in Ontario has been presented, by and large, as 11 something that's going to save customers money. There 12 will be some considerable dissatisfaction if, in fact, 13 rates increased. Accordingly, it may be necessary to 14 add some kind of education program that deals with what 15 is, in fact, going on and how, in fact, an ordinary 16 consumer may best adjust to the new reality and we note 17 that the economies of scale are better served by having 18 one done on a large basis, rather than an individual LDC 19 attempting to initiate one of their own. 20 Finally, with respect to reporting and audit 21 disclosure standards, we believe the reporting 22 information should be subject to audit and, as well, 23 that information should be available to the public and 24 to the representatives of the public, which is 25 particularly critical for the design of second stage PBR 26 framework. 27 Finally, I'm not certain whether or not we can 28 do this in the submission, but we would request that the 209 VECC 1 Board give consideration for the award of costs, to 2 compensate the Vulnerable Energy Consumers Coalition for 3 its efforts in this proceeding. We base this on the 4 fact that, we believe, our participation has been 5 responsible and hope that it adds to a better 6 understanding of the issues in this proceeding. 7 THE PRESIDING MEMBER: Thank you, Mr. Janigan. 8 Dr. Zerker? 9 MEMBER ZERKER: Mr. Todd, turning to your 10 Table B, page 21. 11 MR. TODD: Yes. 12 MEMBER ZERKER: By your methodology, there is 13 no doubt that the higher productivity approach would be 14 a greater incentive to the LDCs. However, I could look 15 at that if I were operating a business and say, "Look 16 it, I can't make 2 per cent, or 2-1/2 per cent, or 3 per 17 cent, and it's not worth me bothering to try and gain, 18 you know, 1, 1-1/2 per cent because I hardly get 19 anything for it". 20 I mean, in some sense, there's a disincentive 21 built in here as well as an incentive. Or do you 22 disagree with that? Because the share to the LDC is so 23 small at the upper range. Unless you had tremendous 24 opportunities to increase your productivity. 25 MR. TODD: The minimum is one. 26 MEMBER ZERKER: Right. 27 MR. TODD: That's built into the system. 28 MEMBER ZERKER: Right. 210 VECC 1 MR. TODD: And if they opt for 1.5, which I 2 would say is pretty minor step up from 1, for the 3 initial PBR period of only three years, yes, there's 4 minimal incentive there. But they only have to get a 5 minimum productivity of 1.5 in order to justify going to 6 the higher level because, at the 1 there is no earning 7 share. So, they start to cash in right away. 8 I mean the benefit of going to 1.5, we being 9 at 1, is substantial because they start to be able to 10 earn a premium over the allowed rate of return. 11 Remember, that the starting point is they are 12 being allowed to earn, and build into the rates, the 13 market-based rate of return. That's the same return as 14 would be earned by a comparable private sector company. 15 So we are talking about the premium over what 16 has traditionally been viewed as a fair return, in 17 regulatory circles, and part of the concept here is, you 18 get a bonus for exceptional performance. You only get 19 your market return if all you do is an ordinary job. 20 And by the time, if they are prepared to target 2 per 21 cent, yes, they have to reach 3.5 to actually make that 22 pay, but they are then getting 50 per cent of all the 23 earnings above the target and they are going to get a 24 30 per cent share of the total productivity gain. 25 That's starting to be substantial. 26 Yes, to get up to 50 per cent of the total 27 productivity gains they have to pick a target of 2.5. 28 But 2.5 for the relatively short period -- a few years 211 VECC 1 for the first stage of PBR -- is not going to be 2 exceptional performance in itself for many municipal 3 electrics. The issue is there's a large diversity. 4 Some of them are going to be able to achieve significant 5 gains through picking low-hanging fruit; others are 6 already tight ships and they may have trouble achieving 7 significant gains. 8 So, it's really a tradeoff between the 9 different situations because we are using a "one size 10 fits all". And under the alternative of Table A, if you 11 have a company that does have a lot of low-hanging 12 fruit, they can pick that fruit and take away 90 per 13 cent of the gain. 14 So, I agree, and as I said in the evidence, 15 there's a judgment call here. What I'm suggesting is 16 that the concept of with higher productivity levels you 17 adjust the earnings sharing is one which you can 18 structure, in my view, more consistently with the goals. 19 The numbers I suggested aren't the only ones you could 20 choose. So if you felt that there was insufficient 21 reward to the utility -- it's your judgement of accounts 22 not mine -- you could shift all those numbers. 23 MEMBER ZERKER: In other words, the sharing 24 that you propose here is not built into your 25 calculations, necessarily? 26 MR. TODD: Well, you changed the calculations, 27 but you could go -- for example, if you felt this was 28 not generous enough, you can go 25 per cent at 1 and 212 VECC 1 50 per cent at 1.5 and 75 per cent at -- 2 MEMBER ZERKER: But the underlying principle 3 that you are proposing is to not identify a performance 4 factor with ROE, at all? 5 MR. TODD: Not using an ROE ceiling. 6 MEMBER ZERKER: Not use an ROE ceiling. 7 MR. TODD: Because that implies 100 per cent, 8 up to the ceiling, which can be a large premium. 9 Incidentally, this approach, adjusting the 10 share of earnings of the productivity factor, was the 11 approached used by the telecoms, in the U.S., and the 12 result there was that most of the companies that had the 13 option moved to very high targets. They did respond to 14 it very strongly. Successfully, by the way. To the 15 benefit of both customers and the company. 16 MEMBER ZERKER: Thank you. Those are my 17 questions. 18 THE PRESIDING MEMBER: Thank you, Dr. Zerker. 19 Mr. Vlahos? 20 MEMBER VLAHOS: Mr. Todd, if we were to use a 21 50-50 earnings mechanism rather than the table that you 22 have, what are the downsides, compared to your proposal? 23 Just 50-50 straight through, no ceiling at all on the 24 ROE. 25 MR. TODD: A few years ago, I think I favoured 26 that approach. That was before we had experience. 27 Experience in B.C. I have been quite involved in the 28 processes out there. 213 VECC 1 It is my observation, and I have to say it's 2 sort of casual observation not scientific proof of it, 3 if you have a target -- I was alluding to this earlier 4 -- if you have a target, that's what the company does. 5 If you have a 50-50 sharing, what's the target? The 6 target may be the minimum level. Management has an 7 incentive to do whatever is necessary to make their 8 owners happy. And if you have kind of a minimum 9 productivity target of 1 or 1.5, with unlimited 50-50 10 sharing, what I would suggest is you are likely to get 11 the 1 or the 1.5. 12 With the company having to choose a 13 productivity target, and there being an incentive to go 14 to higher target, you achieve two ends. Number one: it 15 would be unreasonable for the Board to simply order 16 everybody to have a productivity target of 3 per cent. 17 If you give them a choice, they are going to get some 18 utilities choosing 3 per cent, others choosing 2 per 19 cent, maybe some choosing 1 per cent. They are able to 20 choose themselves, so it's voluntary; they will go after 21 that target; they will discriminate amongst themselves 22 as to what's achievable for different companies; but 23 they will have targets that will reflect their 24 individual circumstances. To some extent, it's voting 25 with their feet, in a corporate way. And having set 26 that target, they will achieve it -- you know, if they 27 choose 3 per cent, they will work really hard to get 28 there. But if they are not forced to choose something 214 VECC 1 higher, they will end up just working for 1 per cent. 2 MEMBER VLAHOS: Mr. Todd, can you tell us are 3 there any criticisms that you may have heard in the last 4 week from the other parties as to this model, or has it 5 been generally accepted? What have been some of the 6 comments that you may want to help us with? 7 MR. TODD: During this week -- I was at 8 meetings all day yesterday, so I haven't heard the other 9 comments and, frankly, I have been in British Columbia 10 and wasn't reading all the papers coming in. 11 That can be addressed in final comments and I 12 am assuming it would be, responding to other parties. I 13 haven't had a chance to follow it. Perhaps Mr. Janigan 14 has. 15 MR. JANIGAN: I would add in the examination 16 of Mr. Todd at the technical conference I don't recall 17 there being any specific comments directed to this issue 18 by any of the parties or any specific criticism 19 associated with this particular proposal. 20 MR. TODD: In fairness, there were only one or 21 two parties there. 22 MEMBER VLAHOS: That was my next question. 23 MR. TODD: Nobody came out to complain. 24 MEMBER VLAHOS: Mr. Janigan, when you suggest 25 that the panel should be incorporated into the plan are 26 you referring to the first generation plan? 27 MR. JANIGAN: Yes. We do believe that 28 penalties should be incorporated into the first 215 VECC 1 generation of the plan and that in order to make 2 performance standards meaningful there should be 3 financial penalties associated with a level of 4 performance. 5 MR. TODD: I think the suggestion is that the 6 principle should be established now and there should be 7 something introduced, but given the absence of data they 8 would be much less stringent I think may be a fair word 9 to say, than they might be in the second generation. 10 But I think it is important to establish the 11 principle that there are consequences. It's a word I 12 use with my kids, you know, you don't get punished. 13 There are consequences to actions and companies have to 14 recognize there are consequences of not achieving the 15 quality standards. 16 Admittedly, they may have to be a little on 17 the weak side given the information we have and we don't 18 want to create a strong disincentive to companies that 19 don't have the information now to making sure they don't 20 have the ability to report and prejudice themselves, but 21 something should be established. 22 MEMBER VLAHOS: Other than just the words, Mr. 23 Todd, should it be -- how far would you like this to be 24 seen in the Handbook? Is there going to be a formula 25 right now with some numbers, or simply the Board saying 26 that the Board intends to link the two through the 27 penalty and the performance through a formula which the 28 Board has not had time to address? I am just not sure 216 VECC 1 how far you want the Board to go at this stage. 2 MR. TODD: The principle that has been used in 3 British Columbia, which I think is a good one, is the 4 concept that a company should not be in the money if it 5 is failing to meet quality standards. In the money is 6 receiving a bonus over the normal allowed rate of 7 return, so that ties in well with the revenue sharing. 8 Whatever the share is that would be earned 9 above and beyond the market based rate of return cannot 10 be retained by the company if it is not meeting 11 performance standards. And where there is flexibility 12 is in the way that those meeting the standard is 13 applied, you can use the three year running average on 14 the measures. There is a choice of measures that you 15 use. The R‚gie in Quebec has a scaling factor where it 16 can meet 90 per cent of your target. You get I think 17 it's 50 per cent of your share and if you are below 80 18 per cent of your target you get none of your share. If 19 you are 100 per cent of your target you get 100 per cent 20 of your share. 21 There are different ways to cut that. The 22 important thing is that for whatever standards you have 23 they should have teeth. So for the standards you have 24 which we are suggesting they should be developed and 25 more refined for second generation PBRs so they are very 26 limited now, but at least to those limited standards 27 there should be a reduction and/or elimination of the 28 retained share above and beyond the market based rate of 217 VECC 1 return if companies fail to achieve those standards. 2 MEMBER VLAHOS: One last question, Mr. 3 Janigan. When you referred to the public education and 4 how it should be done or initiated by the OEB, I 5 wondered whether your aim was to protect the OEB? We 6 are not responsible for those rate changes or the 7 purpose is someone has to tell the customer and the OEB 8 is the best source. Which one is it? 9 MR. JANIGAN: Well, as a former city and 10 regional councillor I am well aware that political heat 11 has a habit of rolling down from one government to the 12 next or the next agency. But it is certainly the latter 13 that I am focused on. 14 I think it is also important that the Energy 15 Board is seen as a fair and honest arbiter of problems 16 associated with the energy industry in Ontario. From 17 looking at the experience in the CRTC where frequently 18 everything is blamed on the CRTC, particularly if there 19 are problems in the cable industry, that it is not a bad 20 idea to have at least some prophylactic mechanism in 21 place that enables the public, or at least the informed 22 public, to know exactly what is going on. 23 But primarily it is the latter that I am 24 concerned with and, in fact, we do inform a significant 25 portion of the small volume consumers in a way which 26 creates enough of a market to introduce market forces 27 and assist in the establishment of a workable 28 competitive market for small volume customers. 218 VECC 1 MEMBER VLAHOS: What channels would you have 2 in mind, Mr. Janigan? What kind of effort are we 3 talking about? Are we talking about bill inserts that 4 the Board may wish to design or vet? 5 MR. JANIGAN: Bill inserts are generally 6 thought to be sort of ground zero in terms of consumer 7 education. They are frequently resorted to. 8 I had some personal and anecdotal cynicism 9 towards bill inserts in a general way. I am not certain 10 whether or not they were utilized in the process of 11 introducing long distance competition. I am not sure 12 that they were effective. 13 I think I would like an opportunity to think 14 of what might be the most effective package in terms of 15 expenditures of dollars and reaching the kinds of 16 consumers that we want to represent. I don't know, 17 John, you may have some more thoughts on that. 18 MR. TODD: On the gas side with the changes 19 that have taken place over the last couple of years, and 20 in anticipation of the spin out from the Energy 21 Competition Act, there were a number of meetings that 22 you may be aware of. The Board was involved with them. 23 Consumer representatives were involved in them, the 24 utilities, the ministry, Energy, Science and Technology, 25 trying to come up with a co-ordination of a public 26 education process. 27 There was some success in co-ordination in 28 getting messages out from various parties. There were 219 VECC 1 also some failures, in large part that disputes over who 2 was going to pay and nobody has been prepared to kick in 3 the funds and I think the utilities were concerned about 4 essentially being guaranteed their costs up front and, 5 therefore, weren't prepared to come up with money. 6 Governments don't have the budgets. Consumer groups 7 don't have the budgets. Marketers want to market, not 8 do public education. They want to do their own 9 advertising, general information that doesn't present 10 their name to the public. That's their business. 11 So a lot of things that were talked about 12 never happened. The public education that resulted was 13 minimal in my view. It would be unfortunate if the same 14 thing happened on the electricity side, given that the 15 changes that are happening are far more significant than 16 they are on the gas side, but I think there is already a 17 risk that is going to happen. 18 MEMBER VLAHOS: Thank you, gentlemen. 19 MR. JANIGAN: Just to follow up on that, at a 20 minimum I think some sort of communication strategy 21 might be of assistance to be developed both for the 22 Board and the suggested strategy with the LDCs 23 themselves. 24 That is the something that is frequently not 25 present. Even in the largest of organizations it 26 wouldn't be very beneficial, particularly in the time 27 immediately after the introduction of competition. 28 THE PRESIDING MEMBER: I just have one 220 VECC 1 question recognizing the time, and that is with regard 2 to the question of rebasing. 3 We have had some comments that the Board has 4 to make some guidance available to people as to how the 5 rates may be rebased when it comes to Phase 2 and, in 6 particular, I believe they relate to whether there will 7 be any sharing of the savings that are a result of 8 productivity improvement. 9 I wonder if you have any comments on rebasing 10 since you have experience on PBR systems in other ares. 11 MR. TODD: Rebasing is a very sensitive issue 12 because with full rebasing it means that the benefits of 13 productivity gains accrue to the utility only in the 14 short term, and with the three-year PBR a maximum of a 15 three-year period. 16 I think that with a stable PBR system it is 17 important not to fully rebase frequently, that there 18 must be some long-term gains in order to have an 19 incentive for the productivity gains. But what we have 20 here is very much a short-term system with a lot of 21 question marks at the end of the day. 22 I think it would be unwise of utilities to 23 really look beyond the three years in any case. It may 24 be appropriate, therefore, to view this is as kind of a 25 special case where we are getting our house in order. 26 We have a one-size-fits-all, which is a very crude PBR 27 system. We know it is going to be radically changed. 28 In my view, you can take it as a three-year system -- 221 VECC 1 there is going to be full rebasing and a whole new 2 system in three years -- and that would be consistent 3 with my concept of what I think is intended in the 4 current PBR Rate Handbook. 5 THE PRESIDING MEMBER: Thank you, Mr. Todd. 6 Is there any matters of clarification, 7 Ms Kwik, that you -- 8 MS KWIK: No, Mr. Chair. Thank you. 9 THE PRESIDING MEMBER: Thank you, Mr. Todd and 10 Mr. Janigan, for your presentation. 11 MR. JANIGAN: Thank you very much, Panel. 12 THE PRESIDING MEMBER: We look forward to your 13 written submission on October 22nd. 14 The next presenter -- I'm sorry. Mr. Janigan, 15 you had something to say? No. 16 The next presenter I believe is Mr. Stephenson 17 from the Power Workers' Union. 18 Mr. Stephenson, should we go straight through 19 or should we break now and then go straight through, 20 immediately following you, to ECMI which follows it? 21 Which would you prefer, to break now or to carry on for 22 the next hour and then break? 23 MR. STEPHENSON: I'm in your hands. I'm happy 24 to proceed now. I don't anticipate how -- subject to 25 what the Board has by way of questions, I'm not going to 26 be all that long. 27 THE PRESIDING MEMBER: The reporters are all 28 right to carry on? 222 VECC 1 Okay. Well, we will continue then with 2 Mr. Stephenson's presentation. 3 Welcome, Mr. Stephenson, from the Power 4 Workers' Union. 5 PRESENTATION 6 MR. STEPHENSON: Good morning. 7 My name is Richard Stephenson. I am counsel 8 for the power workers. 9 We have appeared before the Board on numerous 10 occasions in conjunction with its regulation of the 11 electricity industry in Ontario, in particular, former 12 Ontario Hydro -- 13 THE PRESIDING MEMBER: Mr. Stephenson -- 14 MR. STEPHENSON: Yes? 15 THE PRESIDING MEMBER: -- could you pull your 16 microphone down a bit because I'm not sure whether you 17 are being picked up. 18 MR. STEPHENSON: Sure. 19 -- in particular, through the rate hearings 20 regarding Ontario Hydro in the past. 21 We have been involved in essentially all 22 aspects of both the Board's consultative processes 23 regarding its own new regulatory role as well as the 24 legislative reform process, which has led us to Bill 35. 25 Very briefly by way if background, as you will 26 know, the PWU is a trade union. It represents the 27 largest group of employees of the old Ontario Hydro, and 28 now of all of Ontario Hydro's successor companies 223 PWU, Presentation 1 including OHSC services company, which is particularly 2 relevant in the context of distribution and distribution 3 PBR. 4 In addition to that, we represent employees at 5 15 other electricity LDCs across Ontario, large and 6 small, north and south. 7 We will be filing a written final submission 8 in accordance with the Board's direction. 9 To that extent, in this submission I really 10 want to focus on one issue, and it is an issue which we 11 have a great of deal concern has, if not overlooked, 12 been given insufficient weight in the overall context of 13 the Board's consideration here. I don't mean to say 14 that pejoratively. I think there are some very good 15 reasons why that has been the case. 16 In essence, the subject I want to talk about 17 is about system reliability and customer service. It's 18 a very difficult issue. 19 We were involved with and I sat on the 20 implementation task force that dealt to some extent with 21 this issue. It is a thorny issue. It is difficult 22 because of issues that were not in the control of 23 anybody at the moment, and that is simply the problem of 24 data, that the critical data simply has not been 25 collected systematically by all utilities across the 26 province. 27 So this is very much a situation akin to the 28 situation the task force and the Board consultants came 224 PWU, Presentation 1 across when they were considering yardstick regulation. 2 They just didn't have a data set upon which they could 3 make meaningful comparisons and thereby make fair rules 4 going forward such that it really could be pursued at 5 this time. 6 That all being said, I think there is an 7 enormous risk that this issue be perceived as being some 8 sort of a second class issue or second rate issue, and 9 that what we are really concerned about here is getting 10 economic efficiency, getting the financial house of LDCs 11 in order. In my submission, if that becomes the 12 mind-set, both of the Board as regulator and of the 13 stakeholders generally, then we are going down a very 14 dangerous road in the future because what will typically 15 happen -- and this is, in my view, an intrinsically 16 psychological issue from a mind-set perspective -- is 17 that when we talk about or examine economic efficiency 18 and financial performance of these LDCs that will take 19 up our resources. And when you look at other issues, 20 and system reliability has to serve as a perfect 21 example, it will be viewed as sort of an add on. It 22 will be viewed as something which is a stop gap or a 23 band-aid measure. We don't want things to get too bad 24 on this side. 25 But what is really important are getting these 26 financial mechanisms, economic incentives, right. We 27 don't want to be too intrusive regarding reliability 28 measures or incentives because we are concerned that 225 PWU, Presentation 1 that will distort the kind of economic incentives that 2 we want to put in place. If there is one thing I can 3 leave with you today, in my view, that is precisely the 4 wrong approach. 5 In our submission, and this was I think 6 recognized by all of the various academics and 7 economists that provided assistance to the Board through 8 the consultative process, it is of course an intrinsic 9 element of any PBR scheme that there is an economic 10 incentive to minimize expenditures. 11 It is also a truism that maintaining these 12 systems cost money. There are limits to the technology 13 that can be applied to these to achieve efficiencies. 14 The technologies of course themselves cost money. 15 In a very real sense, what we are dealing with 16 here is a system of hard wires and equipment, 17 transformer stations, and we have poles and wires and 18 associated apparatus. It is a very capital-intensive 19 system. That system must be retained, refurbished and 20 recapitalized on an ongoing basis. 21 It is just something that we have always done, 22 and it has to carry on. There is a stewardship element 23 of the maintenance of this kind of capital-intensive 24 business in order for these assets to be useful for 25 their economic lives. 26 After all, this is still a monopoly element of 27 the business, and everybody foresees that it will 28 continue to remain a monopoly element of the business 226 PWU, Presentation 1 for the foreseeable future. 2 So long-term cost minimization is still the 3 watchword of the day from the perspective of the 4 company, from the perspective of the ratepayers, and 5 from the perspective of society as a whole. 6 The problem is that PBR intrinsically develops 7 economic incentives, many of which are short term in 8 nature, which may directly undermine the notion of the 9 stewardship of those assets through their economic lives 10 in a fashion which maintains a degree of reliability in 11 the system. 12 Let me just say one thing about system 13 reliability; and that is it is a notion that echoes, 14 that resonates through all the discussion regarding 15 electricity restructuring. There is an element of pride 16 in LDCs, in policymakers, in legislators, in electricity 17 consumers, large and small, in this province that we 18 have had an historically high level of reliability in 19 our electrical system. 20 At the distribution level, because it is in 21 essence the direct attachment for customers, it is very 22 much a significant contributor to that overall 23 reliability. Every public utterance from anybody that 24 has studied this has always harkened back to this notion 25 of the historic level of reliability. 26 Those concepts, the critical importance of 27 reliability, got embodied of course directly into Bill 28 35, and significantly it shows up in two different 227 PWU, Presentation 1 places, prominent in both. In the very first section of 2 the Electricity Act, maintenance of the reliability of 3 the electrical system is one of the guiding objectives 4 of the Electricity Act as a whole. 5 Of course, in your own Act you have objectives 6 stipulated for you in carrying out your responsibilities 7 in terms of regulating both electricity and gas. In the 8 case of electricity, the maintenance of the reliability 9 of the system for the benefit of the customers is 10 specifically identified as one of your guiding 11 objectives. 12 Of course, we are here for a very simple 13 reason. We see ourselves in a very direct way as the 14 people who are responsible day to day, hands on, for 15 delivering that reliability and customer service. It is 16 obviously through a variety of different ways. We 17 represent people both in the field, in the 18 administrative area, in the customer services area, and 19 so on and so forth; construction, maintenance and so on. 20 We are the people who do that. We see it day to day. 21 We deliver it day to day. 22 More significantly, through our role with 23 Ontario Hydro and through proceeding before the Board 24 regarding Ontario Hydro, we also saw this issue face us 25 consistently throughout the last half of this decade. 26 Mr. Dominy, I know, was involved in some of 27 these proceedings. In essence, we raised again and 28 again throughout the late 1990s issues about whether or 228 PWU, Presentation 1 not Ontario Hydro was paying sufficient regard to 2 questions of electricity reliability; whether they were 3 injecting sufficient capital, sufficient maintenance 4 budgets to maintain the system. They were slashing 5 those budgets immensely, both in terms of capital and in 6 terms of maintenance expenditures. 7 The Board examined the question, and the Board 8 recognized that there as an inherent trade-off being 9 made; that they fully anticipated that these reduced 10 expenditures would have consequences in terms of 11 long-term reliability of the system. 12 But the Board specifically indicated, given 13 Ontario Hydro's then present financial crisis -- which 14 particular one it was at that moment, I can't recall, 15 but there was a series of them -- that the trade-off was 16 justified. 17 We then moved, somewhat ironically, but the 18 first regulatory proceeding involving electricity under 19 the new regime was OHSC's transmission and distribution 20 rate order applications last fall. In that rate order 21 application, on both sides, distribution and 22 transmission, OHSC came before this Board seeking 23 increased budgets for capital and OM&A; the reason being 24 that they had catch-up to do. They had fallen seriously 25 behind in a number of critical areas of their 26 maintenance program in terms of their schedules, and so 27 forth, and they had to get those things back on track. 28 There is nothing terribly sophisticated about 229 PWU, Presentation 1 this. You reap what you sow very much in terms of these 2 kinds of programs, but it is not something that can be 3 ignored. 4 We fear very much that OHSC is now reaping 5 what it has sowed through the last five years. 6 From our perspective, as we have indicated, 7 there was a general consensus. I have never heard 8 anybody suggest that basically any PBR scheme doesn't 9 provide this negative incentive; that is, to cut 10 corners, reduce expenditures on reliability-based 11 expenditures. 12 One of the reasons why this incentive is so 13 dangerous is that PBR schemes, such as this one, may 14 provide almost immediate returns on an economic 15 standpoint, on a financial standpoint. Particularly 16 where here we have a short period there will be a real 17 incentive on LDCs to make their money within the span of 18 the three years. 19 It is possible, as Mr. Todd suggested, that 20 there will be a complete rebasing at the end, so they 21 have to cash out in the short term. 22 One thing experience tells us is that 23 inadequate investment in the condition of the system 24 doesn't show up in the short term. A dollar not spent 25 today doesn't produce a measurable decrease in 26 reliability or customer service tomorrow. It may not 27 show up a month from now or a year from now, but five 28 years from now it shows up. 230 PWU, Presentation 1 And of course you have to pay the piper, and 2 it is the ratepayer who obviously will be paying. 3 The costs of doing the fix-up job five years 4 hence may in fact be greater, even on an adjusted basis, 5 than the costs would have been to simply maintain and 6 object capital for doing maintenance on an ongoing 7 basis. So there is a perverse incentive built into the 8 system. 9 What is the solution? 10 Well, from our perspective there is a direct 11 solution to this. Unfortunately, it has not been 12 achieved and, unfortunately, we have reached the 13 conclusion that it is in fact not achievable in the 14 immediate term. 15 The answer is that economic penalties must be 16 in place for failure to meet reliability standards. 17 But they are not sort of an add on. They 18 cannot be viewed as something which has been grafted 19 onto a system as a band-aid. They have to be viewed as 20 an integrated element of the PBR scheme as a whole. 21 This is an economic machine and the 22 maintenance of reliability is but one part of the 23 economic machine and that there must be an economic 24 counterbalance which is direct and integrated into the 25 economic incentives so that, of course, the LDC, when it 26 is engaging in its business planning activities, can be 27 looking ahead and governing itself accordingly and 28 making the correct economic choice. 231 PWU, Presentation 1 In this proceeding Mr. Adamson and Dr. Bauer 2 and others talk about the importance of getting these 3 signals right. The key part about PBR of course is to 4 establish signals so that there is self-interest on the 5 LDC to perform in a certain way which the Board wants so 6 that the Board, of course, does not have to maintain an 7 ongoing heavy-handed oversight micro-managing the 8 enterprise. You just get the signals right and they 9 will do what you want them to do. 10 So the key is, of course, to get the signals 11 right on this issue. 12 Mr. Adamson made an analogy which I thought 13 was really quite striking which I thought drove the 14 point home, which is this: If the goal of the system is 15 to produce efficiency you have to be very careful about 16 what you are measuring. 17 He has talked about a car manufacture and he 18 says that, you know, if you have a car manufacturer and 19 they are making a Mercedes Benz for $100,000 and all of 20 a sudden -- and all you are interested in is price, next 21 year you present an incentive and you tell them, "We 22 want you to make a cheaper car". Lo and behold, next 23 year they produce a car which is cheaper. It costs only 24 $20,000. It's a Lada. They are both cars, but they are 25 different cars. 26 The key thing is that when you are 27 producing -- when you look at the electricity system, 28 the system quality is an intrinsic element of the 232 PWU, Presentation 1 identification of a product which is being produced. So 2 the mere fact that somebody can produce a Lada cheaper 3 than they can produce a Mercedes doesn't reflect that 4 they have become more efficient because they are 5 producing a different product. 6 Similarly, here if they are producing 7 electricity which has a lower level of reliability, 8 lower level of customer service, the cost savings may 9 not reflect any efficiency improvements at all. It may 10 simply reflect the fact that they are producing an 11 inferior product. 12 So without intrinsically integrating 13 protection of these issues, the Board may be receiving 14 very false or misleading signals with respect to whether 15 or not there are in fact any true efficiencies being 16 achieved. 17 Now, I characterize this as internalizing the 18 cost. The Board obviously is very familiar with the 19 notions, the economic notions of externalities and how 20 in a variety of areas the key is to attempt people to 21 have the players recognize the costs of negative 22 externalities and reap the benefit of positive 23 externalities. 24 We way simply that you can look at this in a 25 similar way, in that the degradation of system quality 26 of customer service is essentially just a negative 27 externality and the way to ensure that the proper 28 economic outcome, the efficient economic outcome takes 233 PWU, Presentation 1 place, is for the LDC to internalize the costs of a 2 negative externality. 3 So one thing I learned through this process 4 from Dr. Bauer, from Dr. Adamson, from Dr. Cronin, from 5 Mr. Todd, was that in fact there is a reasonably 6 well-established literature and some experience on the 7 ground with respect to integrating economic penalties 8 into a PBR system whereby lower levels of performance 9 against established criteria will automatically produce 10 negative consequences. 11 Moreover, that there has been -- within the 12 literature there is some well-established analysis 13 regarding the magnitude of the penalties. I mean, 14 obviously the penalties have to be big enough such that 15 the LDC won't find it in its objective to -- you know, 16 if you can cut $1 million out of your budget and pay a 17 penalty of $50,000, it is in your economic incentive to 18 do that. It has to achieve the economic outcome that 19 you are looking for. 20 Now, where do we go from here on this issue? 21 Well, it was interesting to hear Mr. Todd this 22 morning talk about how he would like to see some element 23 of penalties on the standards that we have now. 24 I'm not sure the Board has the stomach for 25 that. I would like to see that happen. I'm not sure 26 that you have enough information to feel comfortable to 27 do that. 28 Mr. Todd's answer was that, well, in essence, 234 PWU, Presentation 1 you make them sufficiently modest that, you know, nobody 2 is going to get stung too badly at this stage because 3 you may not have it right. 4 I actually see some merit in that. It is a 5 very imprecise tool, but everything about this PBR, with 6 respect, is a little imprecise. So there is a real, in 7 essence, psychological importance in getting that 8 message out as quickly as possible, that there are 9 consequences for your actions and, importantly, economic 10 consequences. 11 What is contained in the Draft Handbook, as 12 you know, is essentially an administrative answer to 13 this, which is that LDCs which go offside are required 14 to file something called a compliance plan. It doesn't 15 really say much more about what a compliance plan 16 exactly is or what it does or what the Board's role or 17 the LDCs role is and obviously that gives the Board a 18 little bit of room to manoeuvre. 19 Maybe that is the best you can do in the short 20 term. It's not the appropriate answer for a whole 21 variety of reasons and I think the Board will know this. 22 It requires the Board to take an activist 23 role. You know, there is an intrusive element to it, 24 requiring expenditure of resources and so forth on the 25 Board. And, of course, there are enormous informational 26 gaps as between the LDC on the one hand and the Board on 27 the other. So it is difficult for the Board to do. 28 Moreover, in my submission, it gets the math 235 PWU, Presentation 1 all wrong. You cannot provide an incentive to do one 2 thing and then provide an administrative backstop on the 3 other. There is a certain symmetry about keeping this 4 all within the ambit of the economic incentives and 5 having counterbalances on the economic incentives, 6 essentially, getting those incentives so the LDC does 7 the right thing. 8 So that was just to conclude the point by 9 Mr. Todd. 10 I do support that. If the Board feels that it 11 has enough information to go there, in some form of a 12 modest economic penalty, I would suggest in conjunction 13 with an administrative review because the economic 14 penalties may not be sufficient, in the near term. In 15 conjunction with an administrative review, I would be 16 delighted to see that because I think it sends out the 17 right signals. 18 The key thing, from my submission, about PBR, 19 is the first generation is simple, it's imperfect, it's 20 going to make mistakes, and so forth, but get the 21 philosophy out there, number one, and, number two, 22 Board, ensure that you are in as best a position as you 23 possibly can be so that three years hence, when we go 24 into second generation, you are going to have as good a 25 plan as you can possible have. 26 In my submission, one of the elements that you 27 are going to want to have is a sophisticated scheme that 28 deals with this issue about economic incentives or 236 PWU, Presentation 1 maintenance of appropriate reliability and customer 2 service standards. 3 At page 9 of the oral submission that I filed, 4 I set out a number of items that we submit should be 5 made very, very clear, explicit in the first generation 6 Rate Handbook, bearing in mind the limitations we 7 otherwise face. 8 Number one is, perhaps, absolutely obvious; 9 it's simply that the stakeholders, the LDCs, should view 10 the first generation Handbook is essentially an interim 11 step and that they should have every expectation that is 12 going to be extensively revised upon implementation of 13 the second generation scheme. 14 Secondly, I think the Board should say that it 15 intends to include, in the second generation scheme, an 16 integrated system of economic penalties and incentives 17 to govern system reliability and customer satisfaction. 18 That is philosophically the way it is going on 19 integrated systems. 20 Thirdly, that it should send the message that 21 the compilation and reporting of data, regarding system 22 reliability and customer service standards, in a 23 standardized and comparable format, both between LDCs 24 and within an LDC, over time, is an absolutely critical 25 objective for the first generation of PBR. LDCs' 26 compliance with their data collection and reporting 27 obligations will be closely scrutinized by the Board and 28 the failure to rectify deficiencies will be treated very 237 PWU, Presentation 1 serious. 2 I think the Board should think very seriously 3 about having financial penalties for non-compliance with 4 data collection and reporting because what that kind of 5 failure does is an LDC thumbing its nose at you and at 6 -- really jeopardizing not only their own efficiency, 7 they are jeopardizing the ability of the Board to come 8 up with a coherent scheme for all of Ontario. So, they 9 are not only -- they are not just wrecking it for 10 themselves, they are wrecking it for everyone if they 11 don't comply. So, I think that is an absolutely 12 critical objective for the first term and should be 13 treated very seriously. 14 Fourthly, I think the Board should sponsor and 15 should tell the LDCs that it intends to sponsor an 16 independent survey of LDC customers, with respect to 17 customer reliability and customer service issues, during 18 the course of the first term of -- first generation of 19 PBR. I think it's important that that issue be done, I 20 think it's critical that it be done, and I think it has 21 to be done independently of the LDCs. 22 The Board has already, in the Draft Handbook, 23 indicated its intention, or its proposal of the 24 intentions, to get back to mid-term review during the 25 first generation. I think the Board should announce 26 that it intends to do that and should further announce 27 that a key issue in that first mid-term review will be 28 the assessment of progress achieved in the development 238 PWU, Presentation 1 of a database necessary for the implementation of an 2 integrated scheme of economic penalties and incentives, 3 with respect to system reliability and customer service. 4 The Board should also, during the course of 5 that first -- the mid-term review receive input with 6 respect to particular design aspects to be used in the 7 development of the scheme as part of the second 8 generation PBR. 9 I think all of those things should be made 10 loud and clear in the Rate Handbook as, essentially, a 11 backstop against doing what, ideally, should be done at 12 this time. 13 Now, just a couple of small other items that 14 relate, again, to this same issue. In our submission, 15 employee health and safety should be a reported measure 16 within the rule book of system reliability and customer 17 service. It's a related issue in this sense, that we 18 are very concerned that, for the very reason the 19 economic incentive provides perverse incentives on 20 system reliability, they also provide perverse 21 incentives on employee health and safety. There is a 22 culture of safety which has been imbued at LDCs, 23 historically, and we fear that that is in risk of being 24 undermined and we think that the reporting on that will 25 be significant, for two things. One, it will 26 demonstrate a lack of care, which may manifest itself in 27 other ways; and, secondly, it will, we think, provide a 28 discipline on the LDCs to ensure that they keep their 239 PWU, Presentation 1 standards high. 2 Secondly -- and this is echoing a submission 3 made by Mr. Todd and by VECC, in its material -- we 4 think that the MAIFI, the momentary outages index, 5 should be tracked and recorded. We think that it is a 6 useful indicator, both because momentary outages do have 7 economic consequences but also because there may be 8 telltale signs of broader system quality issues. 9 And, lastly, we concur with Dr. Bauer, in a 10 comment that he made, and that is, you may recollect 11 that in the Draft Rate Handbook there is essentially two 12 categories of data, or measures, some of which have to 13 be simply recorded and others which have to be recorded 14 and reported, and we don't really see the justification 15 for maintaining that distinction; we think everything 16 should be reported. We don't think that the burden, 17 either on the LDC or the Board, is materially increased 18 by requiring reporting and that should be done. 19 Just in conclusion, we will be providing, I 20 think, a broader submission in terms of our written 21 submission, but today I really did want to leave with 22 you, in the strongest possible terms, our concern 23 regarding this issue. We think it is historically 24 important. We think that it will be critical in the 25 future. We think that there is a risk, that it is an 26 issue which will be marginalized. We think that it has, 27 in fact, been marginalized already in the manner in 28 which it's been treated throughout the PBR development 240 PWU, Presentation 1 process. It's understandable why that has occurred 2 because there's been so much to do. 3 We support the implementation of PBR. We, in 4 fact, support the Draft Handbook. 5 To a very significant extent we think that it 6 is a substantial piece of work and, frankly, it's very 7 close to as good as can be achieved within the time 8 frame and under the circumstances. 9 We think that going forward in particular a 10 better job has to be done on this issue. We think there 11 is an answer and the answer lies in integrating the 12 economic penalties with the economic incentives, so that 13 you wind up having what PBR is supposed to achieve. 14 That is, it is essentially a self-correcting, 15 self-governing, self-regulating scheme whereby people do 16 what they should do because they perceive it in their 17 economic interest to do so. 18 The key thing from our perspective is to get 19 that message out in the strongest possible terms within 20 the confines of the limitations the Board has faced 21 itself. 22 There is a limited amount it can do now. 23 There is a lot it can do later and the Board must ensure 24 that it uses the time and resources it has in the first 25 generation to guarantee that it is as good a position to 26 get this issue right in the second generation. 27 Those are my submissions. I am happy to 28 assist you if you have any questions. 241 PWU, Presentation 1 THE PRESIDING MEMBER: Thank you, Mr. 2 Stephenson. 3 Miss Kwik, any questions from Board staff? 4 MS KWIK: Yes, I do. Thank you, Mr. Chair. 5 As you recall -- I assume you recall from 6 working on the Implementation Task Force, that task 7 force suggested that there was no need for the Board to 8 require reporting on health and safety because of the 9 ministry guidelines on health and safety that are in 10 existence. What shortcomings do you see of these 11 ministry guidelines that would require the Board to pick 12 up on the reporting for health and safety? 13 MR. STEPHENSON: This will be somewhat 14 anecdotal, but I actually happen to work fairly 15 extensively in this area. The short answer is that the 16 Ministry of Labour doesn't do health and safety any 17 more. They are not in the health and safety business 18 pretty much any more. 19 Once upon a time they used to do that, but 20 they don't have very many inspectors any more. They are 21 all gone. So there is a handful of inspectors that deal 22 with hundreds of thousands of workplaces across Ontario. 23 Our experience has been that the way that 24 health and safety is done in this province now is they 25 wait for somebody to get hurt and they come around and 26 pick up the pieces, and that to a very large degree 27 health and safety is something which is to the extent it 28 happens at all is something which happens by virtue of 242 PWU 1 the commitment of the employer and the employees to make 2 sure that it gets done, as opposed to regulatory 3 oversight. That's point number one. 4 Point number two is that we think there is a 5 danger that the scheme which is being implemented is 6 going to be the source of the problem. To the extent 7 there is a problem now, there will be an economic 8 incentive to get things done faster, quicker, less 9 people and so forth. 10 So just as a backstop or a counterbalance 11 against the negative incentive that the scheme itself is 12 imposing, we think it is appropriate that in the short 13 term at least, and on this issue we are simply saying 14 reporting, that there be reporting. We think that that 15 will provide a strong, at a minimum a moral suasion 16 element to be mindful of these issues. 17 MS KWIK: Thank you. 18 THE PRESIDING MEMBER: Thank you, Ms Kwik. 19 Dr. Zerker. 20 MEMBER ZERKER: I think, Mr. Stephenson, you 21 have covered your point in your argument very clearly 22 and succinctly. I don't really have any questions, 23 except to follow up on Ms Kwik's. 24 I am wondering in your negotiations and in 25 your contracts with your union and your employers do you 26 not have pretty tough standards on health and safety? 27 MR. STEPHENSON: It's not a subject -- I am 28 trying to remember what all the collective agreements 243 PWU 1 look like and I don't even know what they all look like. 2 It's typically not the subject of a collective 3 agreement per se. What collective agreements typically 4 will do, at least more sophisticated ones, is provide 5 for mechanisms for the establishment of, for example, 6 joint health and safety committees and things like that. 7 You won't find in a collective agreement 8 standard regarding work processes per se or complement 9 issues and things like that. 10 MEMBER ZERKER: I disagree with you on that 11 because I have seen -- I don't wish to debate this, but 12 I have seen contracts over the years and they do 13 stipulate standards in many industries. I am not 14 quarrelling with you. You know your own contracts. 15 MR. STEPHENSON: Certainly, in terms of OHSC, 16 which is the single largest distribution utility in the 17 province, you won't find that per se in terms of 18 workplace methodology issues. That's not there. 19 MEMBER ZERKER: Thank you. 20 THE PRESIDING MEMBER: Mr. Vlahos. 21 MEMBER VLAHOS: Just a couple of questions, 22 Mr. Stephenson. Just to follow up on this same point, 23 you don't see a responsibility to the board of directors 24 and the management of the utility in terms of health and 25 safety, employee health and safety -- 26 MR. STEPHENSON: I don't see the 27 responsibility -- 28 MEMBER VLAHOS: -- with the board of directors 244 PWU 1 or management of the utility? 2 MR. STEPHENSON: Absolutely. 3 MEMBER VLAHOS: There may be liabilities which 4 is an economic incentive for them to act in a prudent 5 way when it comes to health and -- 6 MR. STEPHENSON: Absolutely. 7 MEMBER VLAHOS: Okay. 8 I guess I am a little concerned if the 9 Board -- or your suggestion that the Board should fill a 10 void that you have witnessed out there in terms of the 11 ministry, that it doesn't have the dollars and has cut 12 out its activity. I am a little concerned about that. 13 The Board is saying we are going to -- 14 MR. STEPHENSON: Don't get me wrong. I don't 15 mean to suggest that the Board freelances as a regulator 16 on other issues about which it is not its core 17 competency because other people are falling down. 18 I raised that point because the issue is isn't 19 this being dealt with adequately elsewhere? That was 20 sort of the starting point. My answer is you should not 21 assume that's the case. 22 But the most important part or the reason why 23 we raised the issue is really the second part of my 24 submission or my suggestion to Ms Kwik, that we think 25 that the very scheme that the Board is implementing 26 creates a perverse incentive. So, insofar as the Board 27 is responsible for creating the incentive, the Board 28 should at least monitor the consequences that that 245 PWU 1 incentive might create. 2 MEMBER VLAHOS: I was just wondering whether 3 you were aware if that issue has come before the Board 4 on a gas case and what may have been the Board's 5 response? 6 MR. STEPHENSON: I can't help you there. 7 As you know, in terms of its cost of service 8 scrutiny in the gas industry, one of the programs that 9 the Board will review from time to time are expenditures 10 on health and safety issues. At a programmatic level we 11 accept they are spending material amounts of money on 12 these kind of issues. That's something that the Board 13 can and I believe has looked at. 14 I don't believe they look at it in terms of 15 monitoring outcomes necessarily on any comprehensive 16 basis though. 17 MEMBER VLAHOS: Specifically, I guess I am 18 referring to the only PBR regime that exists in Ontario 19 is with Consumers Gas and that is a limited targeted one 20 for the operating and maintenance budget. There was an 21 invitation to the Board to deal with employee health and 22 safety and the Board has declined to do so. I guess you 23 were not aware of that discussion or that decision? 24 MR. STEPHENSON: No, I am not aware of that 25 discussion. 26 MEMBER VLAHOS: My last question, sir -- 27 MR. STEPHENSON: It doesn't detract from the 28 force of my submission though. 246 PWU 1 MEMBER VLAHOS: No, I appreciate that. 2 My last question, sir, is the integration that 3 you speak of between the PBR and the incentives that are 4 afforded under the PBR regime and I guess your 5 suggestion of let's not forget reliability and our 6 quality of service and all of those points were well 7 taken. 8 You did speak of the inadequacy of the data to 9 be able to do something right now -- you know, this year 10 or the first phase of the PBR -- but you would like some 11 appropriate tone, and I guess Mr. Todd would like to 12 take it further and you agree with Mr. Todd. 13 Now, this data limitation I just want to 14 understand. If we do have X systems and some of them do 15 have the data, and you have to help me with this, is it 16 possible for the Board, for the systems that do have the 17 data, to create that integration, that formula, and then 18 do the same as the data is available for the other 19 systems? Is there some unfairness there amongst the 20 systems that you see? 21 First of all, help me with the data as to what 22 exists, what does not exist, how long would it take for 23 the full data set to be available to the Board? 24 MR. STEPHENSON: My understanding is this, and 25 Ms Kwik can correct me if I'm wrong. There are I think 26 two problems. 27 Problem number one is that not all of the 28 utilities -- we thought that all of the utilities 247 PWU 1 maintain at least some of the data, although we could 2 not get the utilities to report that data. They 3 maintain the data for their own purposes and it was -- 4 for example, SAIFI and CAIDI I think are the ones that 5 are mentioned in the draft handbook which are measures 6 of outages. 7 There are problems with those numbers in the 8 sense that the methodology for calculating them is not 9 standardized and it is not standardized in two different 10 ways. It is not standardized as between utilities, so 11 there is slight differences in how they calculate it, 12 and you leave certain things out and you don't include 13 them in. So they are not necessarily that way. 14 Moreover there have, I believe, also been some 15 changes in methodology within particular LDCs over time. 16 So their historical numbers are not necessarily directly 17 comparable against their current numbers. 18 So those are two problems. 19 The other problem is that when you are 20 attempting to compare across utilities you have the same 21 problem you have when you are trying to do yardstick 22 regulation more generally, and that is, it is difficult 23 to know whether the differences in their outage figures 24 reflect anything other than intrinsic exogenous system 25 characteristics which, in essence, they have to live 26 with, because they live in an area that is, in 27 transition terms, skinny, long, thin lines, harsh 28 weather or adverse conditions, you know, low density, et 248 PWU 1 cetera. 2 So certainly in terms of coming up with any 3 meaningful comparisons across utilities, the perception 4 was that it wasn't even possible to come up with 5 meaningful groups in precisely the way it wasn't able to 6 come up with meaningful groups for yardstick regulation 7 more generally. 8 I see Ms Kwik nodding. I think I have that 9 sort of right. 10 MS KWIK: That is the same understanding that 11 I have come out with. 12 MR. STEPHENSON: Now, then the question 13 becomes, assuming that cross-utility comparisons are, at 14 least in the short term, not useful: Is it possible to 15 come up with the more limited objective of taking same 16 utilities' data over time? 17 I would have thought the answer to that is 18 yes, that there is some utility in that. In essence, 19 that is what the Board -- the draft handbook recommends, 20 because they require a reporting of historical data and, 21 in essence, that is the benchmark, that your own actual 22 performance -- I have forgotten now whether it is 23 measured over time or just last year. Whatever it is, 24 it doesn't really matter, the problem is to come up 25 with, I believe -- and I confess not to have the 26 requisite expertise about all the intricacies of coming 27 up with the quantification scheme -- is to figure out 28 how you measure the value of a penalty which is imposed 249 PWU 1 by virtue of, you know, a .1 per cent decline on a 2 year-over-year basis on a particular measure. 3 It is my understanding that in fact a lot of 4 work has and is being done in this area internationally. 5 I don't think I can assist you further. I don't have it 6 at my fingertips and I haven't seen it in the context of 7 this proceeding. So I would have thought over the short 8 term something can be done economically, taking a 9 year-over-year approach within a particular utility. 10 Whether that can be done in a meaningful way 11 beyond sort of what Mr. Todd sort of -- I took Mr. Todd 12 to almost talk about token penalties. That is sort of 13 what I meant him to say -- I understood him to say. 14 Whether or not you can take it beyond that point to have 15 some meaningful nexus between the deterioration on the 16 one hand and the size of the penalty on the other I 17 can't help you with, I'm sorry. 18 MEMBER VLAHOS: So where would that leave the 19 Board, Mr. Stephenson, if there are those problems as 20 you have mentioned, the value of the penalty, it is an 21 issue which I am sure will occupy plenty of effort and 22 discussion? 23 My interest is in the short term, as we move 24 into the commencement of the PBR. What is available to 25 the Board? I guess that is my question. 26 MR. STEPHENSON: Well, there is a very 27 Draconian penalty which is arguably available. It is 28 the very one that Mr. Todd discussed. He discussed it 250 PWU 1 not only today but elsewhere in this proceeding, and 2 that is the scheme about being "in the money", and that 3 is: Do you get any return, permitted return, above the 4 standard market-based return if you fall, you know, 5 below a prescribed level? 6 It is the opportunity to have a very Draconian 7 remedy. But, as you heard Mr. Todd also say, you know, 8 there are all sorts of little fixes you can put on that 9 about sharing, and benchmarking, and 90 per cent, 80 per 10 cent and so forth. 11 I think, as much as I would like to see it, I 12 think that is ambitious and there is some risk there. 13 My instinct is I think there are two things that can be 14 done. Certainly, the administrative oversight, which is 15 foreseen in the draft Rate Handbook must be done. 16 You know, we talked at the committee about -- 17 or the sub-committee about, you know, well, what is the 18 ultimate sanction if somebody doesn't comply. The 19 answer of course, the ultimate sanction is, you pull 20 their licence. But that has the problem of being so 21 Draconian as well that it may not be seen as having any 22 real teeth because the Board would be so loathed to take 23 the ultimate step. 24 But, in any event, an element of 25 administrative oversight is clearly required in the 26 first term, and the fact that it requires an excess 27 regulatory burden on both you and the LDC is the price 28 we all have to pay on this one I think. 251 PWU 1 I do think, though, that Mr. Todd is right. I 2 think that there should be some kind of -- it will have 3 to be an arbitrary number. By definition, it will be an 4 arbitrary number. But I think that there is some merit 5 in simply having some form of an economic penalty. Of 6 course it will be, you know, something against their 7 return. I mean, it is not going to be -- I don't think 8 you are going to be assessing a fine per se, but there 9 is a structure of doing that. 10 I don't think we are talking about hundreds of 11 thousands of dollars, but we are certainly talking about 12 thousands of dollars and maybe tens of thousands of 13 dollars in the short-term as just a clear signal about 14 two things: number one, this is serious; and, number 15 two, this is economic. 16 MEMBER VLAHOS: And the economic will have to 17 be determined at the time that the information comes 18 forward. 19 MR. STEPHENSON: I fear that we are in for the 20 long haul on this one, Mr. Vlahos. But I think that an 21 enormous amount can be achieved, you know, in the next 22 three years. I suspect this is one of these issues that 23 there will be fine tuning on, on PBR for literally the 24 next generation. 25 MEMBER VLAHOS: Thank you, Mr. Stephenson. 26 Thank you, Mr. Chairman. 27 THE PRESIDING MEMBER: Thank you, 28 Mr. Stephenson. 252 PWU 1 I have just one quick question and that is 2 this question of -- I think in your introduction you 3 expressed concern about the reduced maintenance work 4 that is being conducted that lead to long-term impacts 5 on the performance of the system. I was wondering, in 6 the context of performance measures, what sort of 7 performance measures guard against them, because the 8 performance measures we see are actually the result of 9 possibly the historic lack of activity? 10 MR. STEPHENSON: I don't think the measures 11 can -- aside from a trend analysis, that they won't 12 provide a predictor per se. Looking at a single year in 13 isolation won't tell you anything about what effect the 14 LDC's current level of activity will have in terms of 15 future performance. 16 You are correct there. I don't think you can 17 compensate for that using outage and other reliability 18 measures that are gathered, essentially, real time and 19 recorded historically. 20 There are other predictors that you could use, 21 and one of the items that we outlined in our initial 22 submission was whether or not it was appropriate for the 23 LDC to essentially track and retain and/or report 24 essentially its maintenance routines; that is, talk 25 about what are the average age of its major facilities 26 types tracked against the manufacturer's specifications. 27 In this year's OHSC hearing we had some 28 horrific statistics about the average age of their pole 253 PWU 1 systems, those wooden poles that carry the lines. 2 Something like -- I probably have the numbers wrong, but 3 they have, as you can imagine, millions of poles. And 4 half of them are already beyond their life expectancy. 5 They are not replacing them at a rate which even 6 compensates for the ones that are, on an annual basis, 7 getting beyond their life expectancy, let alone making a 8 dent in the backlog. 9 It is possible to structure a reporting 10 mechanism to do that. 11 My own expectation is that at this point in 12 time I don't think that can be done necessarily in the 13 PBR scheme. I just think it is too burdensome. That is 14 my initial thought on it. 15 Where I think that will have to go, from a 16 regulatory perspective, is into the distribution system 17 code process which is being developed concurrently. 18 There are various reporting mechanisms which are 19 contemplated for the purposes of that code, and that 20 might be the place that it goes. 21 It is a problem, Mr. Dominy. I think the real 22 answer is that you take the SAIDI, CAIDI and MAIFI, and 23 all the other acronyms, as being essentially a proxy 24 about what is going on, recognizing their limitations. 25 To some extent the current owners are being 26 punished for the sins of the prior owners, but that is 27 what you have bought. 28 THE PRESIDING MEMBER: Thank you very much, 254 PWU 1 Mr. Stephenson, for your presentation on behalf of the 2 Power Workers Union. The Board looks forward to your 3 final submission. 4 MR. STEPHENSON: Thank you. 5 THE PRESIDING MEMBER: I believe we should 6 break for 15 minutes. I apologize for Mr. White and 7 ECMI; we are running a bit behind. If we could break 8 for 15 minutes, I think it would be good for everybody. 9 --- Upon recessing at 1130 10 --- Upon resuming at 1148 11 THE PRESIDING MEMBER: Now it is the turn of 12 ECMI. It is Mr. White, and I don't know the other 13 gentleman's name. 14 MR. WHITE: The gentleman beside me is Rick 15 Groulx. He is also a principal in ECMI. We are here 16 representing eight municipal electric utilities, all of 17 which were, over the last year, involved in an 18 acquisition of Ontario Hydro distribution systems within 19 their municipal boundaries. 20 THE PRESIDING MEMBER: Mr. White, are the 21 utilities that you represent listed somewhere? 22 MR. WHITE: I will read them. They were 23 listed on some of our earlier submissions. They include 24 Bracebridge, Caloden, Collingwood, Gravenhurst, 25 Haldimand, Lincoln, Nanticoke and West Lincoln. 26 THE PRESIDING MEMBER: You are right. It is 27 on page 4 of your first submission. 28 PRESENTATION 255 ECMI, Presentation 1 MR. WHITE: One our clients, pre-expansion, 2 would have been classified probably as one of the micro 3 utilities in Ontario, with less than 500 customers. The 4 fact that the utilities have expanded, from a customer 5 base perspective, as much as six-to-sevenfold, it means 6 that the impact of those expansions is material. 7 There are some 20 utilities which have 8 undergone expansions in the last 12-month period, and 9 that represents almost 10 per cent of the utilities 10 remaining in Ontario. Therefore, we consider this to be 11 a relatively significant component. 12 We were most encouraged to hear the response 13 during the technical session of both Board staff and 14 Board consultants that at the start of PBR there was a 15 clear need for us to construct a reasonable history, had 16 they had control and management of the works for a base 17 period for the PBR considerations. 18 What I intend to do this morning, rather than 19 read the oral presentation which you have before you -- 20 which may help in some ways on getting you back on 21 schedule -- I will just go through the general topic 22 items and supplement the oral material that is there and 23 maybe highlight it. 24 I would encourage the Board and Board staff, 25 if they are comfortable with that approach, to ask me 26 questions on a topic basis, if you find that convenient. 27 We are genuinely interested in making this 28 process work for the Board and the Board staff and our 256 ECMI, Presentation 1 clients, by putting a whole together and getting a clear 2 set of rules early we will all have a chance to move 3 through this process effectively. 4 I am going to move directly to contributed 5 capital, which is certainly a hot button. 6 I think one of the things that has been said 7 and accepted by all the pros and cons on contributed 8 capital is that getting it right in the beginning is 9 really important. What the Board has the opportunity to 10 do, and what Board staff and Board consultants have 11 tried to do in the PBR Handbook, is to recognize that 12 not only is electricity turned by a switch but this 13 marketplace that we are in is being turned by a switch. 14 It is going from a public sector, municipally controlled 15 and operated utility, into a private sector, OBCA-type 16 company. 17 In the longer term we are looking at yardstick 18 regulation; at least that is what we have been 19 encouraged to believe is the likely fallout at the end 20 of the initial three-year period. If that is going to 21 be the case, then getting it right at the beginning is 22 even more important. 23 When we talked with the Board consultants and 24 other consultants, we asked them universally: Would 25 utilities who took contributed capital tend to have 26 lower rates or higher rates in an historic regime? 27 And universally, the answer we got back was 28 that they would have lower rates. 257 ECMI, Presentation 1 What that says, if the Board fails to 2 recognize the difference between pre-OBCA companies and 3 post-OBCA companies, is that those utilities under the 4 short-run PBR regime, whose customers have had the 5 benefit of lower rates because of the contributed 6 capital, will continue to have lower rates during that 7 period and continue, probably or quite possibly in the 8 yardstick regime, to possibly inappropriately pulling 9 down the rate base that the OBCA companies have and the 10 whole yardstick base level that they come in at. 11 I think we have to look at contributed capital 12 and where it came from. It came from clearly a public 13 sector regime. The municipality for development charges 14 passed by-laws which took contributed capital and put it 15 in the hands of the clerk of the municipality and it was 16 made available to the utilities. 17 In passing those by-laws the municipal 18 councils and decision-makers paid a political price for 19 making those decisions, if not a direct economic one, 20 because the development that would happen within their 21 community might well be influenced by the development 22 charges that are put in place. 23 Contributed capital within subdivisions is 24 similarly taken from developers, or in some cases from 25 individual customers if you are talking commercial 26 installations, but it is done in a public sector 27 concept. If you strip away that contributed capital 28 from the rate base historically, then you are not 258 ECMI, Presentation 1 providing even those customers who made those choices to 2 pay those prices, or those councils who made the 3 decision to take that contributed capital, to revisit 4 those decisions. That is not an opportunity that we 5 have. 6 So in order to get the basis right and the 7 customers treated equitably it is our position that 8 there should be some recognition of the historical 9 contributed capital. 10 In many cases the municipality itself may have 11 provided the contributed capital from its tax base, at 12 least in part. This occurred often in the case of urban 13 development or redevelopment situations where the 14 municipality was looking for a higher standard of 15 distribution system than would be the normal standard 16 that the utility would put in place. 17 So in looking at it, I don't look at it 18 personally from a purely economic efficiency 19 perspective, but I am prepared to support a fair market 20 value return because it reflects the investment that the 21 customers whose current proxy in the post-OBCA company 22 environment, at least initially, is the municipality. 23 The municipality has a special trust relationship with 24 its constituency and if you don't allow contributed 25 capital into the rate base you may, in some way, 26 undermine that specific trust relationship. 27 As a compromise we have suggested that the 28 Board may wish to consider not the historical rate of 259 ECMI, Presentation 1 return that the utility would have earned on the 2 contributed capital but the maximum rate of return that 3 the utility would have been allowed under the previous 4 regulatory regime, which was not a fair market rate of 5 return, it was a proxy for a reasonable level of risk, 6 that risk being the municipal long-term cost of debt was 7 the maximum rate of return, or the forecast for that was 8 the maximum rate of return that utilities were permitted 9 to earn by the previous regulator. 10 We feel that in the conversion to an OBCA 11 company from a municipal electric utility that that is a 12 reasonable compromise. I'm sure there are municipal 13 utilities that would disagree that that is reasonable, 14 but I think it is fair to say that my clients could 15 accept that. 16 THE PRESIDING MEMBER: Dr. Zerker has a 17 question. 18 MEMBER ZERKER: Two questions. 19 Do you have any data about the proportion of 20 contributed capital that would be representative for 21 your client, as going into the system now. 22 MR. WHITE: Okay. Some of it -- incidentally, 23 I didn't clarify that, but going forward we see the 24 rules to have changed and have no problem with future 25 contributed capital being excluded from the rate base. 26 We work with a number of clients and I have 27 huge volumes of numbers in my head, some which are -- I 28 have some level of confidence of their immediate source, 260 ECMI 1 but it is not uncommon for even small utilities to have 2 contributed capital in the order of 40 per cent. So, 3 you know, it is a significant implication for them. 4 Because of working capital constraints, 5 because of a period of rate freezes, they have all 6 worked hard to squeeze whatever economies they can out 7 of their distribution systems, in part because they saw 8 this expansion coming forward and the need for some 9 flexibility as they went through that process. 10 As a result, they were bumping up against 11 working capital constraints and that is why many of them 12 did not earn a higher rate of return during that base 13 period. A lot of them would be facing similar to zero 14 numbers. 15 MEMBER ZERKER: So while you don't have any 16 specifics on either each or in total, you suggest that 17 it is a significant proportion of their total? 18 MR. WHITE: Yes, it is. 19 MEMBER ZERKER: The other question that I 20 have, just to clarify, is this proxy for risk that was 21 in the previous regulatory system. What would you say, 22 was that around 5-6 per cent? 23 MR. WHITE: I think it was -- it was the 24 municipal long-term cost of debt as opposed to the 25 Canada-long, and I think the number is probably closer 26 to 7, in that order. 27 MEMBER ZERKER: Thank you. 28 --- Pause 261 ECMI 1 MR. WHITE: The price cap is an interesting 2 mechanic and I think during the short term -- I'm sorry, 3 I will wait. 4 THE PRESIDING MEMBER: I was just wondering, 5 Mr. White, whether this proxy for risk -- it was 6 consistent throughout the Ontario systems? 7 MR. WHITE: Yes, it was. 8 THE PRESIDING MEMBER: Was it governed by the 9 same -- what was the instrument? Was it a provincial 10 instrument? Was it a municipal instrument? 11 MR. WHITE: Ontario Hydro, as the regulator, 12 published that figure annually and that figure was their 13 best forecast for the regulated period of the municipal 14 cost of long-term debt. It provided one number for the 15 province. 16 THE PRESIDING MEMBER: Thank you. That helps. 17 MR. WHITE: Thank you. 18 The PBR Handbook is a good first cut at how we 19 all get through the transition period and the incredible 20 effort that has been put into it by Board staff and 21 consultants and in fact people from the industry is 22 appreciated by ourselves and our clients. 23 It is important that when you put a price cap 24 in place that you don't penalize the utilities that move 25 right to the price -- or that don't move right to the 26 price cap initially or we will get a level of volatility 27 that may create that sticker shock that we heard so well 28 capsulized earlier. 262 ECMI 1 I will have some specific comments on the rate 2 impacts. I have some numbers that I think the Board 3 might find interesting when we get into rate impacts. 4 But if a utility chooses to defer moving to 5 the price cap permitted, it is our suggestion that that 6 margin that they fail to take advantage of permitted by 7 the PBR, that that be allowed to be accrued and carried 8 forward even into the post-three year PBR period. 9 If I can go back to one of the comments that I 10 heard yesterday, or one of the questions that was asked: 11 Will the standard of service fall as a result of PBR 12 regulation and the new measures? 13 I think my assessment is that it won't 14 necessary fall but it will change. It will change 15 substantially for many, many communities, particularly 16 the smaller ones, because what the previous regulatory 17 regime did is in large cases it allowed locally elected 18 or appointed commissions to establish the standard of 19 service for that community. 20 What the performance measures that the Board 21 comes forward with will define a new provincial standard 22 and, in the longer term, that standard will prevail and 23 possibly to the detriment of existing local standards. 24 Now I don't know whether helps with the 25 question yesterday but I think it's something that may 26 well flow out of the price cap regime. 27 THE PRESIDING MEMBER: Can I just ask a 28 question. 263 ECMI 1 By that statement are you saying that if the 2 general standard, the provincial standard, is lower than 3 that other particular utility that they will drop their 4 performance to the lower standard? Vice versa, if the 5 general standard is higher, they would have to increase 6 it to the standard. Is that what you are -- 7 MR. WHITE: That's not only what I'm saying. 8 Okay? What I'm saying is there may be other things that 9 are not measured by the Board's standards that are part 10 of the current standard of service. I guess if you go 11 back historically, a pot in every kit, you know, and 12 every kettle, might be a standard that a particular 13 municipality might embrace or a level of redundancy for 14 certain sizes of load or a particular type of 15 construction that provides the alternatives for loop 16 feeds and increased reliability, which may or may not be 17 measured directly by the measures the Board puts in 18 place. 19 Yes, businesses will, over the long term, go 20 to meet the standards that the Board imposes and will 21 consider the cost implications of exceeding those 22 standards. 23 THE PRESIDING MEMBER: Thank you. 24 MR. WHITE: Under the level playing field, 25 it's important, in addition to the comments that are 26 there, to recognize that the clients -- most of the 27 clients that we represent here, and many of those that 28 we don't, now have unique distribution systems in 264 ECMI 1 Ontario. They are not the traditional urban core. They 2 are an urban core plus a mixture of rural, including 3 farm and low-density and intermittent occupancy and all 4 of those other good, normal classifications that we have 5 seen from Ontario Hydro. Part of our concern regarding 6 the measures that are put in place is you might want to 7 capture some additional measures that may capture the 8 density character of these unique utilities which now 9 have huge rural service areas within their boundaries. 10 So, I guess, as a caution, or as request, I 11 would say, going forward, you aren't going to maybe be 12 able to compare all of the municipal utilities of a 13 comparable size on the same basis because those that 14 have a rural mixture will certainly have a higher level 15 of exposure to lightning and line exposure to outages so 16 that there needs to be some recognition going forward 17 that a set of standards may end up not being unique or 18 may not be -- I'm sorry -- may end up not being 19 universal, in terms of their actual application. 20 In terms of the connection of new services, 21 where utilities have -- are at the point of connecting 22 to their lines, they may not have exclusive control over 23 the ability to do that connection. The line may be a 24 load transfer from Ontario Hydro Services Company and 25 they may have to go to them for permission to connect, 26 to add load, and those kind of measures need to be taken 27 into account, not only for the clients we are 28 representing here but for many other utilities who are 265 ECMI 1 dependent upon Ontario Hydro's distribution system for 2 delivering the power to their municipal boundaries. 3 With respect to cost of service studies, I 4 think -- and I appreciate Ms Kwik's comments. I think I 5 heard her, in her opening remarks, clarify that there 6 may be latitude to depart from the PBR Handbook 7 guidelines without doing a full cost of service study, 8 in recognition of things like customer impacts. I know 9 the language she used seemed to suggest that to me and I 10 would be interested in whether I understood or didn't 11 understand it. 12 --- Pause 13 THE PRESIDING MEMBER: Perhaps you could carry 14 on and Ms Kwik can -- 15 MR. WHITE: Okay. 16 MS KWIK: I'm sorry. Are you waiting for a 17 response? 18 MR. WHITE: I thought I would give you a 19 chance. I was going to go on to the next item. 20 MS KWIK: Can you repeat your statement? 21 MR. WHITE: Okay. Fair. 22 The initial position that I thought existed in 23 the PBR Handbook -- and if I'm wrong, I would embrace 24 being corrected in that misassumption -- was that if you 25 were going to depart from the specific pricing regime 26 included in the PBR Handbook that that departure would 27 require a full-blown cost of service study. 28 If that's the case, then it's possible, when 266 ECMI 1 we get into some of the rate impacts, that you will 2 understand my concern. But if it's not the case and 3 departures from the specific pricing mechanisms within a 4 class, as opposed to between classes, is acceptable, 5 based on acceptable levels of customer impacts, then I 6 would take some encouragement from that and still go 7 forward. 8 MS KWIK: The proposal is that utilities who 9 have their own cost of service at the start of the first 10 generation can choose to use their own cost of service 11 circumstances. 12 What I was referring to in my opening 13 statement was how the utility that goes with the model 14 continues with their existing rates -- if there is a 15 significant rate impact within the class -- could handle 16 that rate impact in terms of mitigation. 17 MR. WHITE: Good. I think that was a "yes". 18 Rate impacts -- 19 MEMBER VLAHOS: Mr. White, can I just -- 20 MR. WHITE: Sure. 21 MEMBER VLAHOS: -- try to understand. 22 Can someone do a partial cost allocation study 23 or cost of service study -- let's look at a cost 24 allocation issue -- and I don't know all the issues 25 that you have in mind but let's look at a cost 26 allocation issue. Within a class or within classes, it 27 doesn't matter. Before you get to that point, you have 28 to do a cost of service study. So I'm just not sure as 267 ECMI 1 to what you mean by "partial cost of service" study, or 2 a selective one. I just don't know how it works. Maybe 3 you can help me. 4 MR. WHITE: I accept your -- 5 MEMBER VLAHOS: Puzzlement. 6 MR. WHITE: -- observation, that you either 7 have a cost of service study or you don't. 8 My observation and -- 9 MEMBER VLAHOS: I am sorry, sir, I am saying 10 this because I don't know. I am looking for guidance. 11 Could you have a selective study without having a full 12 study to start with and then you go to the pieces of it 13 and see if it accomplishes the objective you want to 14 accomplish by applying it to a rate design? 15 MR. WHITE: The issue we have got is that, 16 first of all, none of my clients that I am representing 17 here, nor most of my clients across the province who are 18 a much broader group in terms of size, have a current 19 cost of service study. They are all in some way going 20 to be relying on the simplified unbundling process which 21 Board staff and consultants and technical group 22 creatively came up with, which I think is to their 23 credit. 24 My concern was how do you address customer 25 impacts within a class having used that unbundling 26 process. In other words, first you unbundle the cost of 27 power component out of the revenue that the class 28 accrued and the assumption is that after you have made 268 ECMI 1 whatever adjustments are required is that the residual 2 amount is the distribution cost and that must be 3 recovered through distribution rates. 4 As soon as you -- if you accept those dollar 5 figures as an opening point, then utilities may be able 6 to identify their distribution systems as potentially 7 having larger variable cost components than are the norm 8 and that can be done through an assessment of the 9 distribution system without doing a full cost of service 10 study. What it would support would be possibly 11 increasing the variable component in the pricing 12 mechanism which would in fact be a departure from the 13 .62 mills in the PBR handbook -- I am sorry, 6.2 mills. 14 MEMBER VLAHOS: So you are looking at 15 different ways of allocating an amount between block one 16 and block two. 17 MR. WHITE: Within the same class. 18 MEMBER VLAHOS: Right. But then, in order to 19 determine what that amount is you have to go through a 20 cost of service analysis, wouldn't you? That's where I 21 need a bit of help. 22 MR. WHITE: I am not convinced that a full 23 detailed cost of service study -- first, it is not 24 practical in the time constraints and I am not sure that 25 in the long term it produces a substantive benefit if it 26 requires such things as coincident demand 27 identification. 28 If we are moving to a yardstick type regime in 269 ECMI 1 the long term, then the performance of the utilities 2 will be based on those constraints, as opposed to a cost 3 of service methodology. 4 So I am concerned that clients we represent 5 don't have the financial resources to do a full cost of 6 service study, but an assessment of what the specifics 7 supply configuration to a class -- to customers within a 8 class would be might be helpful in mitigating, both 9 mitigating customer impacts, but probably providing 10 better cost signals to customers. 11 MEMBER VLAHOS: That's fine, Mr. White, 12 continue. I just want to make sure that I am clear. I 13 don't advocate that a full cost allocation study be done 14 when it does not have to be done. It is just more of a 15 learning question. 16 MR. WHITE: That's fair. 17 MEMBER VLAHOS: It gets to point "B" before 18 you -- can you get you get to "B" before you do "A"? I 19 guess we will learn. 20 MR. WHITE: We don't have an "A", but we have 21 some numbers that fall out of our best surrogate for "A" 22 and that would be taking the cost of power out and 23 coming up with a class revenue requirement and calling 24 it distribution costs. So then it becomes an allocation 25 issue within the class. 26 If the Board is prepared to live with a 27 constraint, I would like to carry on with some specific 28 customer impacts. The customer impact analysis that I 270 ECMI 1 have is from a client that I am not representing in 2 these proceedings. Therefore, I would rather not 3 disclose specifically who that client is, but I think 4 the fallout numbers may help the Board in terms of 5 understanding the relative impacts that may happen. 6 For the specific customer that we looked at -- 7 I am sorry. Are you okay with that? 8 THE PRESIDING MEMBER: Yes, we are. You are 9 not going to identify it? The customer or the utility 10 isn't identifiable, is it? 11 MR. WHITE: Right. That's what I am saying, I 12 do not wish to identify it. 13 THE PRESIDING MEMBER: But if you give us the 14 numbers it is not identifiable? 15 MR. WHITE: It is not identifiable. 16 THE PRESIDING MEMBER: That's the issue. 17 Okay. 18 MR. WHITE: Thank you. 19 But they are to my best estimates of the data 20 we have currently available. Like we don't have the 21 transmission charge from Ontario Hydro. We aren't 22 really sure exactly what the IMO charges are going to 23 be. Both of those items would put upward pressure on 24 the level of customer impacts that I am looking at, 25 particularly if they flowed into the service charge 26 component of the pricing structure which seems to be the 27 only alternative given the PBR regime and the Draft PBR 28 Handbook. 271 ECMI 1 We looked at small, low use residential 2 customers, currently paying a minimum bill. If the 3 draft PBR handbook rules, as we understand them, were 4 carried forward without the impact of taxes or the full 5 market value rate of return without those impacts, the 6 customer bill would move to about $21.50. That 7 represents an increase of 133 per cent for that 8 customer. 9 If we add the impact of moving to the full 10 market value rate of return using the 975 and using a 25 11 per cent tax rate, the increase would grow to 337 per 12 cent increase. That means the bill would be 437 per 13 cent of what the original bill would be. 14 THE PRESIDING MEMBER: Can I ask a question on 15 that? 16 MR. WHITE: Sure. 17 THE PRESIDING MEMBER: I am not sure where the 18 numbers are going. 19 As I understand what you told me, it is that 20 just by changing the structure of the rate and moving -- 21 does it include the cost of power or just the 22 distribution component? 23 MR. WHITE: It includes an estimate for the 24 cost of power before and after. The after figure we are 25 using is 4.8 cents a kilowatt hour, representing what we 26 understand to be the 3.8 guarantee, plus a CTC charge 27 which, depending upon who I listen to on a given day, is 28 somewhere between .7 and 1 cent. 272 ECMI 1 THE PRESIDING MEMBER: And no transmission 2 costs? 3 MR. WHITE: No transmission and no 4 distribution costs and no IMO charges. 5 THE PRESIDING MEMBER: But then when you are 6 making this increase, the reference from which you 7 are -- that it goes to included transmission -- 8 MR. WHITE: No. 9 THE PRESIDING MEMBER: -- and effected the IMO 10 in the sense that the existing system had some costs for 11 this, managing the power system? 12 MR. WHITE: Yes. 13 THE PRESIDING MEMBER: So the reference didn't 14 include them or did include them? 15 MR. WHITE: The base did include them because 16 it is the existing rates that the customer is currently 17 pay. 18 THE PRESIDING MEMBER: And this is for a low 19 volume -- 20 MR. WHITE: Basically, it is the customer 21 paying the minimum bill today. 22 THE PRESIDING MEMBER: So the effect is to 23 have a larger minimum bill? 24 MR. WHITE: Yes, substantially. 25 THE PRESIDING MEMBER: Carry on. 26 --- Pause 27 MR. WHITE: We did a similar analysis -- I'm 28 sorry? 273 ECMI 1 THE PRESIDING MEMBER: Ms Kwik has a question 2 to ask. 3 MS KWIK: Maybe you are getting to this 4 anyway, but I wanted to know, the impact that you stated 5 of 130 per cent, that was on the total bill. Correct? 6 MR. WHITE: Yes. 7 MS KWIK: And that was for the lowest -- a 8 residential class low consumer, on the low side. 9 What was the average impact within the 10 residential class? 11 MR. WHITE: I wish I had -- I'm sorry. 12 The average impact on the residential class, 13 without making the adjustment in the rate of return, and 14 without making the adjustment for the taxes -- 15 MS KWIK: Yes, the same base which is 130 -- 16 MR. WHITE: -- would have been zero. 17 MS KWIK: Okay. 18 MR. WHITE: Okay? 19 MS KWIK: So when you did your analysis, 20 you -- 21 MR. WHITE: I'm sorry. No, I haven't worked 22 in the new cost of power. I don't know what the impact 23 would have been. 24 MS KWIK: Okay. 25 When you did your analysis, your impact 26 analysis, did you set revenue neutrality at the class 27 level or at the average consumption for the class? 28 MR. WHITE: At the class level. 274 ECMI 1 MS KWIK: At the class level. Okay. 2 What was the range of impact; 130 being the 3 maximum? 4 MR. WHITE: I wish I had had the resources and 5 the time to punish the numbers enough to be able to give 6 you broader examples. I think that was part of what we 7 were trying to get at when we were in the technical 8 conference, saying: Is there a dollar level, is there a 9 per cent level at which the impact would be perceived to 10 be acceptable? I think, you know, the percentage 11 numbers are different if the dollars are small, the 12 acceptability. So, no, I have not completed sufficient 13 analysis to answer that. 14 MS KWIK: Thank you. 15 MEMBER ZERKER: Can you repeat your dollar 16 numbers? I have your proportions. 17 MR. WHITE: The base level was twenty-one 18 fifty and the subsequent level was twenty-four fifty- 19 eight. 20 THE PRESIDING MEMBER: That is $21 per month? 21 MR. WHITE: Yes. 22 MEMBER ZERKER: Twenty-one fifty. And then 23 the first -- 24 MR. WHITE: The first number was without the 25 rate of return and tax adjustment. 26 MEMBER ZERKER: Right. And it was, in 27 dollars, twenty-four...? 28 MR. WHITE: Twenty-four fifty-eight is the 275 ECMI 1 number I have for the post -- 2 MEMBER ZERKER: Twenty-four fifty-eight. 3 And the third number? 4 --- Pause 5 MR. WHITE: I don't know that I have enough 6 paper here. Can I undertake to provide that number? 7 THE PRESIDING MEMBER: Ms Kwik, have you a 8 clarification? 9 MS KWIK: I have one more question, Mr. White. 10 MR. WHITE: Sure. 11 MS KWIK: The customer that had the 130 per 12 cent impact, what was the consumption level, the monthly 13 consumption level. 14 MR. WHITE: That will probably identify who 15 the utility is because they are somewhat unique. It 16 would be -- 17 MS KWIK: But it was the lowest -- 18 MR. WHITE: It would be the minimum -- the 19 amount of consumption included in the current minimum 20 bill. Okay? 21 MS KWIK: Okay. Thank you. 22 MR. WHITE: So that creates your worst 23 economic -- I'm sorry -- your worst percentage impact, 24 because the customers, if they use X amount of energy 25 that is in there and under the new scheme the energy 26 falls outside of that, they pay for it directly. 27 THE PRESIDING MEMBER: The minimum bill at the 28 present time, what is that; 50 kilowatt hours a month? 276 ECMI 1 Roughly? 2 MR. WHITE: It varies from utility to utility 3 and is -- it typically deals with somewhere between 60 4 and maybe -- certainly less than 100 kilowatt hours a 5 month. 6 THE PRESIDING MEMBER: Thank you, Mr. White. 7 MEMBER VLAHOS: Mr. White, I may be the only 8 one in the room, but I just don't have a full 9 appreciation of what we are talking about. Can I just 10 try to put some questions and see if you can help me. 11 What you are trying to tell us is that you 12 have taken a small-use residential customer and you are 13 looking at the minimum bill. Is that what you are 14 looking at, the minimum bill? 15 MEMBER VLAHOS: I'm looking at the smallest 16 use customer in the utility that would -- I'm sorry -- 17 the largest use customer in the utility that would still 18 pay a minimum bill. That is the one that will have the 19 worst impact. 20 MEMBER VLAHOS: All right. The largest 21 customer in the utility in the residential class that 22 would have the -- 23 MR. WHITE: That would pay the current minimum 24 bill. 25 The interesting thing about the proposal in 26 the PBR Handbook is the minimum bill no longer exists. 27 You end up with a fixed service charge, as some 28 utilities now have, plus a charge for energy. 277 ECMI 1 What I have looked at is the customers who are 2 currently on the minimum bill structure. Let's say it 3 was $6 and the first rate was .10 cents a kilowatt hour, 4 that would include 60 kilowatt hours in that minimum 5 bill before the customer paid above $6. 6 MEMBER VLAHOS: All right. 7 MR. WHITE: Okay? 8 So what I did was, for the particular utility 9 I looked at, I looked at what the minimum bill 10 consumption would be, compared the minimum bill that the 11 customer would pay with the bill that the customer would 12 pay following the rules in the PBR Handbook for those 13 same 60 kilowatt hours, if you will. 14 MEMBER VLAHOS: Okay. 15 But that is not a total bill perspective, is 16 it? 17 MR. WHITE: It is for that customer, yes. 18 MEMBER ZERKER: But that customer just pays 19 the minimum bill, because he just -- 20 MR. WHITE: Currently. 21 MEMBER ZERKER: -- uses the amount that would 22 permit him under the minimum bill scheme. Is that 23 correct? 24 MR. WHITE: Exactly. 25 MEMBER VLAHOS: I see. 26 So whatever consumption was allowed or was 27 included in the minimum bill, now you assume the same 28 consumption, but now it is charged differently? 278 ECMI 1 MR. WHITE: Yes. 2 MEMBER VLAHOS: It is charged on an energy 3 basis, on a variable basis. Okay? 4 MR. WHITE: Yes. 5 MEMBER VLAHOS: Again, forgive me, but I want 6 to get those inputs right. 7 So you are starting off with a total bill of X 8 -- do we have the X on a monthly basis? 9 MEMBER ZERKER: Yes, $21.50. 10 MEMBER VLAHOS: Twenty-one fifty. Okay. And 11 then -- 12 MR. WHITE: No. I'm sorry, the $21.50 is 13 without the addition of taxes and the rate of return 14 increment. 15 MEMBER VLAHOS: Which is the numbers that 16 would apply today. 17 MR. WHITE: Yes. But that is not what the 18 pricing structure exacts today. 19 THE PRESIDING MEMBER: Mr. White, perhaps the 20 easiest way to do this is if you, in your final 21 submission, just define this -- 22 MR. WHITE: I will try and give you a specific 23 table. Okay. That is fair. 24 THE PRESIDING MEMBER: And also we can go 25 through by talking about it to get an understanding. 26 MR. WHITE: Okay. We then went on and looked 27 at the general service class, and I think in our oral 28 submission that is being submitted we identified that 279 ECMI 1 there were significant transition boundary issues where 2 a customer is below 50 kilowatts of demand and above 50 3 kilowatts of demand. 4 In this particular case, if we were to compare 5 the exclusive of any energy constraints, the below 50 6 kilowatt customer for this utility, without the tax 7 implications, would pay $50; with the tax rollout and 8 rate of return implications, it would go to almost $58. 9 That is a below 50 kilowatt customer. 10 As soon as a customer hits 51 kilowatts, 11 without necessarily any change in energy, just by 12 possibly a slightly different use pattern for the 13 energy, the bill would go from $50, before tax and rate 14 of return rollup, to $387. With the tax implications 15 and the rate of return rollout, it would go to $469 a 16 month. 17 On its own, the $50 service charge for the 18 below 50 kilowatt customers creates some concern for me 19 in terms of what the impact might be on some of our 20 infrastructure. I don't mean the electric utility 21 infrastructure; I mean the social infrastructure. 22 The current minimum bills in the general 23 service class customer are typically paid by phone 24 booths that have a light in them, an electric light, and 25 that might go from a current minimum bill, under the 26 current pricing regime, of $6 to $50 under the proposal 27 in the PBR Handbook for this specific utility. 28 I think that might cause the telephone 280 ECMI 1 industry, or some others who are using relatively small 2 volumes of electricity for security and other kinds of 3 implications, to make some decisions that might not be 4 in our communal best interest. And that is outside of 5 the arena that my customers have given me direction on. 6 I think the dollar figures are substantive 7 enough to cause me to have some concerns. 8 MEMBER ZERKER: Fundamentally, what this is 9 all about is some slippage from the smaller categories 10 to the -- I mean slight slippage from the smaller 11 category to the larger category, and there is no smooth 12 transition or range. 13 Is that what you are demonstrating here? 14 MR. WHITE: The current pricing regime is 15 conceptually an integrated structure, ignoring energy. 16 Put the energy somewhere else. Even without the energy, 17 it is an integrated pricing structure. 18 It provides, because of the blocking that is 19 in the pricing structure, for a smooth transition as 20 customers go from one consumption level to the next, so 21 that there isn't a huge bottom line dollar change in the 22 bill. Those kinds of pricing mechanics have been around 23 a long time. 24 In other words, if you have a zero to 50 25 kilowatt sub-class, then they would face a service 26 charge. Typically, the demand charge would kick in at 27 51 kilowatts, so that you don't get a huge transition. 28 The energy price would adjust, or the variable cost 281 ECMI 1 component in the new regime would adjust downwards to 2 reflect the fact that more revenue was being recovered 3 from the demand component. 4 So there are ways of modifying the structure 5 to create a smooth transition as customers move from one 6 class to another. 7 The minimum bill that we have expressed 8 concern about is not the minimum bill that the normal 9 customer would pay. It, like so many other aspects of 10 the assessment that we are trying to do on the fly as 11 the industry goes through revolution, or evolution 12 depending upon whether you are inside or outside, it is 13 a minimum bill consideration which would reflect a 14 significant contractual -- I'm sorry, a significant 15 capital commitment by the distributor. 16 In other words, if they were going to go out 17 and build 50 miles of three-inch gas pipeline to supply 18 a customer at the end of it, a gas supplier might look 19 for a guarantee. And that guarantee and the price 20 associated with that guarantee need to be part of the 21 regime, as we go forward. 22 It has to be married, closely integrated with 23 whatever CIAC regime -- contributions in aid of 24 construction -- that the Board comes up with for such 25 expansions so that the customer approaching the utility 26 gets a reasonably equitable shake-out out of that kind 27 of pricing regime from the utility, and at the same time 28 the utility and its other customers are not potentially 282 ECMI 1 left with the stranded asset should that customer fail 2 to take power over the longer term. 3 THE PRESIDING MEMBER: Can I clarify. Are you 4 talking here about -- supposing there is some idea that 5 it costs a normal amount to attach a customer; that 6 would be covered. But if the customer lives exceedingly 7 far away from the transmission line or the distribution 8 line, they have to have extra line in to serve them. 9 And it is how you handle those customers that costs a 10 lot to connect. 11 Is that what you are talking about? 12 MR. WHITE: At least partially, but I am not 13 thinking so much about the residential customers as the 14 large commercial customers who might require a 15 three-phase line. 16 THE PRESIDING MEMBER: So they have to have a 17 higher but more expensive connection than the normal run 18 of the mill business, is what you are saying. 19 MR. WHITE: If they locate on an existing 20 three-phase feeder with adequate capacity, then the 21 utility's exposure is minimal. If the utility, because 22 they want to locate five miles down a side road from 23 that feeder, has to build five miles of line which is 24 largely dedicated to that particular customer, then they 25 need some guarantee that the revenue stream that would 26 normally flow from that doesn't go away. 27 THE PRESIDING MEMBER: In the existing system, 28 that is captured by contribution. That is the way it is 283 ECMI 1 done? 2 It is not captured by the rate structure, is 3 it? 4 MR. WHITE: Actually, it is captured by often 5 a combination of capital contribution and in some cases 6 special minimum bill, which includes a base charge plus 7 so much per kilowatt of connected load or contracted 8 amount. 9 So there is a recognition of the significant 10 investment that the utility has in supplying the 11 individual load. That is in the current pricing regime. 12 THE PRESIDING MEMBER: But is that something 13 that is negotiated with the specific customer so you can 14 individualize minimum bills for a particular customer? 15 Or is it part of the rate structure? 16 MR. WHITE: Yes. It is often negotiated with 17 the individual customer, and that's why the words 18 contracted demand are included in the minimum bill 19 provision. 20 THE PRESIDING MEMBER: Thank you. 21 MR. WHITE: If the Members of the Board have 22 any other specific questions, I would like to try and 23 answer them. 24 I really appreciate your attention, and I hope 25 I haven't sounded the knell that it's all gloom and 26 doom. I think the problems we have identified are 27 solvable by mitigation mechanics or a level of 28 flexibility and pricing within the class that can deal 284 ECMI 1 with these transition issues. 2 MEMBER ZERKER: I just have some 3 clarification. 4 You were talking about your customer -- 5 previously in your example of customer impact and you 6 were talking about a minimum bill. Now you are talking 7 about a minimum bill which is kind of a specialized 8 contract. 9 MR. WHITE: Yes. 10 MEMBER ZERKER: Are these two different items 11 or two different approaches or two different 12 applications within a utility's methods of charging 13 their customers? 14 MR. WHITE: The minimum bill I talked about 15 initially was the typical residential kind of minimum 16 bill, which is avoided costs and basically says you have 17 to send somebody out to read the meter and you have to 18 issue a bill and hopefully at some point get some 19 payment. 20 The type of contracted for supply services 21 minimum bill is a different kind of minimum bill because 22 it has two components. Typically it would have the base 23 service charge as a component of it plus so much a 24 kilowatt for the contracted demand. So it has an 25 ability to scale it to a large investment situation that 26 the utility might be faced with. 27 MEMBER ZERKER: That makes sense to me. 28 Could I go back and ask you, in your 285 ECMI 1 submission on rate impacts you informed the Board in 2 your first paragraph that although the PBR Handbook 3 assumes something that assumption is wrong, that there 4 was total and absolute compliance with the model that 5 was used by Ontario Hydro in the MEA. 6 So you are telling us that there was a model 7 but it wasn't really followed. 8 MR. WHITE: What the models used by Ontario 9 Hydro's regulator did was to establish -- and it was 10 brought out in the technical conference -- the 11 residential end rate test was a floor for that rate 12 level and utilities were allowed to price above that 13 rate level. 14 That doesn't mean that they didn't follow the 15 model. The model established a floor. 16 When you looked at the aggregates of the 17 revenues produced by the residential class you found 18 that the revenues produced weren't that dissimilar from 19 what you would get by applying the model. So that what 20 the utilities often stated they were reflecting other 21 than just preference in terms of how they price the 22 product but was the fact that the losses might be higher 23 in a utility producing a higher variable cost or there 24 might be density situations within a utility where the 25 incremental distribution costs would be higher because 26 the design of the system was a more stretched out system 27 with fewer revenue-producing customers on it. So those 28 kind of constraints were dealt with by how the 286 ECMI 1 guidelines were applied. 2 That is somewhat what we are looking for in 3 terms of the application of the initial guidelines in 4 the PBR guide as opposed to just saying there is one IDC 5 for the entire province and pricing should not reflect 6 in any way a different than normal incremental 7 distribution cost that might have traditionally been 8 recognized for that utility. 9 Utilities in general, incidentally, operated 10 at 3 per cent above that test level. If I translate 11 that all into an IDC component it requires over a 60 per 12 cent increase in the 6.2 mils. 13 MEMBER ZERKER: What I hear you say is that it 14 is not a question that they didn't comply. You used the 15 word "compliance" and that suggested to me that there 16 were deviations that were unacceptable. 17 But what you are saying, and correct me if I 18 am wrong, is that the system permitted flexibility or 19 variability and that what you are looking for is a 20 system in the new regime that is also variable or 21 flexible, adaptable to specific conditions. Is that 22 your argument? 23 MR. WHITE: I think, yes, in a nutshell. 24 I think I would go further and say that if the 25 Board establishes the constraint that it should move in 26 the direction of more heavy emphasis on the service 27 charge over time, I think most of my clients would be 28 comfortable with that. What they are worried about is 287 ECMI 1 that sticker shock that might drive customers to draw 2 questionable conclusions about the whole process that 3 the utilities are involved in and what they are doing 4 and what their motives might be. 5 MEMBER ZERKER: Going back to your price cap 6 argument, you said that you would like a mechanism to 7 carry forward the unrealized revenue if the utility does 8 not take advantage of the full opportunities. How long 9 should they be able to carry that forward? It's not 10 like tax losses that you are going to buy and sell, or 11 at least I hope it isn't. 12 MR. WHITE: Me too. 13 I haven't put my mind a whole lot to that 14 particular concept, but given the level of the 15 structural change that the industry is facing and what 16 the impact might be, if you were to say that the impact 17 is 10 per cent, then if I were to say that an acceptable 18 adverse customer impact was 1 per cent a year, I would 19 say, you know, 10 years and they will find some way to 20 squeeze some more out of the process during that period. 21 THE PRESIDING MEMBER: Mr. Vlahos? 22 MEMBER VLAHOS: Thank you, Mr. Chairman. 23 Mr. White, just one set of questions. 24 There is a nominal impact that would come 25 about into the distribution cost as well as commodity, 26 transportation, et cetera, of this whole exercise of 27 restructuring. There has been some discussion here 28 that, well, we are definitely going to see some cost 288 ECMI 1 pressures on the distribution side and we don't know yet 2 what is going to happen on the other side. The net we 3 don't know. In the short run you may see some increases 4 on net. 5 Now, is your concern overall as to this 6 overall impact to the customer, to the small or 7 residential customer, or is it the presentation of the 8 new bill that will be arriving at the door? 9 MR. WHITE: Maybe I would like to ask a 10 question. 11 If you are talking about the impact of going 12 to a market value rate of return and the impact of 13 introducing taxes to fund -- or PILS to fund the debt 14 that is deemed to be required to be funded that way, 15 then I don't think myself or my clients are concerned 16 about that. They recognize that that is part of going 17 forward and changing the industry and living with those 18 consequences. 19 Our concerns flow from the other components. 20 First place, there are two aspects on that. 21 All of that implication within the residential class the 22 way the PBR Handbook is designed, all of the 23 implications of that flow into the service charge, okay. 24 In addition, whatever amount was in the 25 variable price component, before, within the residential 26 class, in terms of the pricing structure, in excess of 27 the .62 cents, all of that flows into the service 28 charge. 289 ECMI 1 So what I'm concerned with is a pricing regime 2 that produces immediate impacts on customers, 3 notwithstanding whether the marketplace is restructured 4 and taxes have to be paid and rate of returns are 5 permitted. The percentage impact that we came up with 6 was 133 per cent, without the implications of the tax 7 and the rate of return implications. So that's purely a 8 choice, in terms of how much you recover from the 9 variable component and how much you recover from the 10 fixed component. 11 Frankly, from a very selfish perspective, my 12 clients might be best to say, "Give it to me all in the 13 service charge; it's very predictable, I know I'm going 14 to get it whether they use one kilowatt hour or not". 15 My customers know their customers well enough to know 16 that these kind of percentages will be headline grabbers 17 and may make the transition for them even more difficult 18 than it needs to be. 19 Does that answer your question? 20 MEMBER VLAHOS: I believe it does, yes. 21 So, even if you -- if you are not considering 22 all the other cost pressures, if you only take what's 23 given today and you are just changing the rate structure 24 to capture all the costs other than the 6.2 -- 25 MR. WHITE: Yes. 26 MEMBER VLAHOS: -- then that, in itself, gives 27 a shock to certain customers, and those customers will 28 be the customers that will be small and -- 290 ECMI 1 MR. WHITE: My recollection of that is that 2 40 per cent of those customers are seniors. 3 MEMBER ZERKER: Don't look at me. 4 MR. WHITE: No. No. Well, I noticed that you 5 pay attention when I bring up some of what I consider to 6 be really sensitive issues. I'm feeling close to being 7 a senior myself. 8 MEMBER VLAHOS: That's not to say the other 9 two don't pay attention. 10 --- Laughter 11 MEMBER VLAHOS: I think I understand, sir. 12 Now, I just have one request, with the leave 13 of the chairman, and that is, I know, and you know, that 14 the rate impact is a very important issue in this 15 proceeding and all of us will be assisted, including 16 people that are not here today, to see, in a 17 spreadsheet, okay, in a page, as to what exactly you are 18 talking about. You volunteered to do that, as far as 19 your submission. I'm just wondering whether -- you 20 know, that's one page to discuss the things, you know, 21 it's to set out what you discussed today and put all the 22 appropriate assumptions -- if that can be available 23 sooner than that, so that it can be available on the 24 record and parties can use that accordingly. 25 MR. WHITE: Last night, I encountered some 26 midnight madness as I was putting together these numbers 27 so that they are not in a format that I'm comfortable 28 with turning out, at this point. 291 ECMI 1 The other thing is the numbers in behind those 2 would readily identify particular utilities. So, if you 3 were to look at how the numbers were derived, you could 4 figure out who the utility is, and I don't have their 5 permission. 6 MEMBER VLAHOS: Mr. White, I didn't mean to go 7 as far as you have interpreted my request. 8 Simply, what you have given us on the record 9 today is in a lengthy discussion today and I'm just not 10 sure of the clarity of the record on the examples you 11 brought forward, so all I'm saying is: whatever is on 12 the record, put it in one page or two. So residential 13 customers; I believe you talked about general service 14 customers were up. If that can be made available before 15 your submission, for all parties to have, I think that 16 the whole process will be assisted. 17 MR. WHITE: I would certainly be happy to make 18 that summary available. 19 MS KWIK: Would you like that as an 20 undertaking, then? 21 MEMBER VLAHOS: Yes, please. 22 MS KWIK: It will be Undertaking 2.1. 23 UNDERTAKING NO. 2.1: Mr. White to 24 produce summary, as discussed 25 MEMBER VLAHOS: Thank you, Mr. White. 26 THE PRESIDING MEMBER: Mr. White, I have one 27 question only, and it's related to the utilities you 28 represent. 292 ECMI 1 Now, I understand that they have all acquired 2 area or assets from Ontario Hydro Network Company and my 3 understanding is that they are, therefore, in receipt of 4 rural rates assistance -- 5 MR. WHITE: Yes. 6 THE PRESIDING MEMBER: -- which will be 7 declining over a five-year term, or three-year term, in 8 some cases, because they have already got -- and I was 9 wondering how will you treat that? You have a decline 10 in revenue coming to the utility from the rural rate 11 assistance that the legislation entitles you to have. 12 How would that be reflected in the way in which you go 13 forward with your rates? 14 MR. WHITE: I think our clients will be 15 conservative in the amount that they feel they can 16 squeeze out of PBR because of the contraction of the 17 rural rate assistance component of their current cost 18 revenue stream. 19 I think, further, that it may allow some of 20 them to bring their debt/equity ratio in line with the 21 imputed capital structure of 50-50, certainly over the 22 five-year period. But they may -- at the very least, 23 they are going to be stressed by the process. The 24 normal life for one of the managers of one of these 25 expanding utilities is, "How do I survive 'til I get to 26 go home? And when I get to go home, how many calls will 27 I get tonight to deal with issues that are evolving". 28 So I think my planning, somewhat like theirs, will be 293 ECMI 1 constrained by the financial implications associated 2 with this, as well as the operational considerations. 3 Tracking the PBR measures that we ultimately come up 4 with is going to be a significant administrative burden 5 for all of the smaller and some of the small-, 6 medium-sized utilities. It's not going to be an easy 7 process. We understand the importance of it. But these 8 are, you know, upward pressure on costs, downward 9 pressure on rates and some desire to show some enhanced 10 performance when many of these utilities may have 11 squeezed millions of dollars out of the predecessor 12 pricing regime structure for the benefit of their 13 clients. 14 THE PRESIDING MEMBER: Mr. White, thank you. 15 Ms Kwik, have you any clarifying questions? 16 MS KWIK: No, we don't. Thank you, Mr. Chair. 17 THE PRESIDING MEMBER: Mr. White, thank you 18 very much for your presentation. 19 We will break, now, for lunch and, with 20 Mr. Adams' agreement -- I see him in the audience -- 21 could we come back at two o'clock, rather than 1:45, to 22 give us a break? 23 So we will resume at two o'clock, then. I saw 24 Mr. Adams nod his head. 25 --- Luncheon recess at 1306 26 --- Upon resuming at 1400 27 THE PRESIDING MEMBER: Ms Kwik is there 28 anything that needs to be done before we start? 294 ECMI 1 MS KWIK: Not for us. Thank you. 2 THE PRESIDING MEMBER: Thank you. 3 Welcome Mr. Adams. You are caught, so to 4 speak. 5 PRESENTATION 6 MR. ADAMS: It's a privilege to appear and 7 make our presentation. What we intend to do with our 8 presentation is, with the permission of the Board, to 9 depart somewhat from our written presentation and focus 10 on some of the areas that are most important to us and 11 that we want to emphasize for the Board. 12 My name is Tom Adams. I am representing 13 Energy Probe and with me is my colleague, Michael 14 Hilson. We are both authors of the statements that have 15 been put onto the record and we were both participants 16 in the technical conference as well. 17 Energy Probe's interest in this proceeding is 18 focused on ensuring a fair and efficient outcome in the 19 development of MEU rates and LDC rates going forward. 20 Although we have made submissions on several points 21 related to PBR and are generally supportive of the move 22 towards PBR, we intend for the purposes of our oral 23 presentation to focus on the rate increases that are 24 implicit in the Board's staff proposal, leaving aside, 25 just in the interest of time, our submissions on the 26 detailed implementation issues, with an invitation to 27 members of the panel or to Board staff to pursue them in 28 questions if necessary. 295 ENERGY PROBE, Presentation 1 The real concern that brings us here today is 2 the rate implications, the rate shock, which we 3 anticipate to be approximately a 35 per cent increase in 4 the distribution rates which, as we will argue in our 5 presentation, we think is at least partially and perhaps 6 wholly unnecessary. 7 The context for our presentation is our 8 reading of the government's policy in the electricity 9 restructuring and that being to deliver the lowest 10 possible electricity prices to end-use consumers. We 11 have several references in our paper that we have drawn 12 upon in basing our claim that that is the appropriate 13 approach to pursue in this case. 14 The two elements of the Board's issues list 15 that we want to focus on here are items 3 and 4 from the 16 issues list that was distributed in the invitation to 17 the parties in making their presentation today. The 18 first is the allowable rate of return on contributed 19 capital in the existing rate base. The second is the 20 calculation of market based rate of return. 21 Energy Probe finds itself in substantial 22 agreement with the municipal utility intervenors in this 23 proceeding in finding that there is no logical 24 distinction to be made between two different forms of 25 utility capital, contributed capital on the one hand and 26 retained earnings on the other hand. We consider that 27 both forms of capital are effectively contributed by the 28 same group of customers. 296 ENERGY PROBE, Presentation 1 The distinction between these two forms of 2 capital is that contributed capital was contributed by 3 some customers for specific assets, whereas retained 4 earnings was contributed by all customers for general 5 service. We think that for rate-making purposes the 6 common recovery policy, a common treatment of both forms 7 of capital is appropriate. 8 That's pretty well on this whole subject of 9 capital and future rates where Energy Probe and the 10 municipal utilities part company. For example, the G-10 11 group have argued that a rate reduction in the rate of 12 return on contributed capital will give customers an 13 improper price signal. We take issue with that argument 14 and have made our presentation in writing on that point. 15 More basically, with regard to the market 16 based rate of return, under Bill 35 the ownership of 17 municipal utility assets has been clarified by assigning 18 that ownership to the respective municipalities. We 19 support that approach and we think that it is favourable 20 for the long-term interests of Ontario's electricity 21 system. 22 The proposal to allow utilities to select a 23 higher return on equity cap, provided they commit to a 24 higher productivity factor is also sound. We are also 25 persuaded by intervenor arguments for allowing earnings 26 in excess of the cap, provided that they are shared with 27 ratepayers in some equitable fashion in an effort to 28 encourage efficiency. 297 ENERGY PROBE, Presentation 1 We note that if the Board adopts our approach 2 to the basic underlying problems we see in the Board 3 staff proposal about which we have referred to as double 4 payment and double counting, then the importance of 5 adopting some kind of shared savings mechanism raises in 6 importance. 7 Energy Probe also agrees with the principle of 8 market based rate of return for utility investments; 9 investments that are required to service customers. We 10 do not agree with the proposed treatment that would 11 entitle -- about who should be entitled to rate of 12 return on investments made when the municipal utilities 13 were operated as co-ops, nor do we agree with the 14 proposed rate-making method that would add market based 15 rate of return onto existing rates without adjustment, 16 since we take the position that existing rates already 17 embed returns on capital. 18 We believe that some adjustment should be made 19 to the distribution revenue requirement prior to adding 20 on the market based rate of return. 21 Energy Probe estimates that the OEB staff 22 proposal would hit customers with an estimated increase 23 of approximately $550 million per year, which is more 24 than one-third more than existing distribution rates, or 25 approximately 6 per cent of total electricity bills for 26 municipal utility ratepayers. 27 The proposed plan widely imposes a new burden 28 on ratepayers. It takes money out of the electricity 298 ENERGY PROBE, Presentation 1 system at a time when Ontario Hydro's liabilities are 2 being absorbed by the market. 3 If the OEB staff plan is pursued, Energy Probe 4 is concerned that ratepayers will blame their higher 5 rates on unbundling and competition, when the real 6 culprit is the substantial transfer of wealth to 7 municipalities implicit in the Board staff plan. 8 It is understandable that in the restructuring 9 of Ontario's electricity system without an Ontario 10 taxpayer bailout of Ontario Hydro's liabilities rates in 11 the short term might rise due to those liabilities. 12 After all, the utility has liabilities far in excess of 13 its value and it is now time to pay the piper. 14 However, with Ontario's municipal utility 15 distribution rates the proposed increases are, in our 16 view, counter-intuitive. Distribution utilities are 17 flush with close to a billion dollars in cash and 18 marketable securities. Just think about that for a 19 minute, a billion dollars in cash. Think of any place 20 else in the economy where a billion dollars in cash 21 might exist. That's more than the liquidity 22 requirements of the federal government I am sure. 23 The utilities have no debt. Their 24 infrastructures appear to be in reasonable condition for 25 the most part. The fact that they have this huge amount 26 of cash on hand is clear evidence that the historic 27 rate-making practice has been inherently inefficient. 28 We believe that customers have been overcharged 299 ENERGY PROBE, Presentation 1 historically. 2 In our oral presentation at the technical 3 conference we noted the inequity of ratepayers being 4 charged again with interest for assets, the cost of 5 which they have already paid. We also set out several 6 possible remedies to this distortion, albeit some within 7 the OEB's purview and some outside of the OEB's purview, 8 including a special dividend to ratepayers or having 9 municipal utilities absorb a portion of Ontario Hydro's 10 debt. 11 We also noted the partial double-counting in 12 the calculation in the market-based rate of return. I'm 13 going to walk through this a little bit. 14 Existing rates already include the capital 15 requirement. That is the capital budget of the utility. 16 This capital budget is generally far in excess of the 17 depreciation on the rate base assets currently in the 18 utility. This is because the depreciating assets in the 19 rate base were purchased over a span of decades when 20 prices and the size of the utility were lower. 21 Using assumptions of 4 per cent per year real 22 utility growth, 4 per cent inflation, and a weighted 23 average asset life of 20 years, the current year capital 24 requirements are double the depreciation on those assets 25 that are depreciating on the books. 26 Anecdotally, the average ratio of large 27 utility reported capital spending versus book 28 depreciation that we were able to obtain from statements 300 ENERGY PROBE, Presentation 1 from a selected group of utilities, including Hydro 2 Mississauga, the old Toronto Hydro unamalgamated, and 3 Hamilton Hydro, is that the capital spending is 4 approximately twice the book value, confirming the 5 calculation that we are going to speak to in a second. 6 I want to emphasize that this is a serious 7 flaw in the proposal itself that will raise rates by at 8 least 20 per cent alone, this double-counting problem, 9 due to the capital intensive nature of the municipal 10 utility business. It is proper to apply a market-based 11 rate of return, but existing rates have to be adjusted 12 to eliminate this double counting. 13 Let me take the example of Consumers Gas. 14 Consumers Gas, as the Board will know, does not pass 15 through its annual capital budget just in the year that 16 the capital budget is -- when the money is expended. 17 That does not flow through to rates in the rate year. 18 It flows through to rates as the customers utilize the 19 assets. 20 They are allowed a depreciation on the 21 existing rate base, which is considerably less, often, 22 than the current capital because the utility is growing, 23 the current capital budget. They can get a market-based 24 rate of return on the rate base, which includes the 25 current year capital spending. 26 In the case of municipal utilities we have to 27 adjust the current revenue requirement, which includes 28 the complete capital spending requirement, before adding 301 ENERGY PROBE, Presentation 1 back the market-based rate of return. 2 It might be worthwhile to point out that 3 historically the reason that this very unusual 4 circumstance arose and why the utilities had the capital 5 structure that they had in the ratemaking formulation 6 was that part of the hydro family -- there was one part 7 of the hydro family, Ontario Hydro, with 100 per cent 8 debt, and another part of the hydro family with 100 per 9 cent equity -- one was that the design of the utility 10 structure for the distribution side of the business, 11 going back to ancient times, to the turn of the century, 12 was that the utilities were to be very conservatively 13 managed. 14 What can be more conservative than making 15 long-term investments but expecting the customers to pay 16 upfront for all of those long-term investments. 17 On Table No. 1, and we have a few extra copies 18 if there are people that don't have them, but we have a 19 calculation of the difference between the current 20 capital spending and the book depreciation. The formula 21 is kind of complicated because you have all these years 22 of depreciation that kick in versus the capital spending 23 which is a lump sum and the -- 24 MEMBER VLAHOS: Mr. Adams, I'm sorry, so that 25 I don't lose you from this point on, can we just go back 26 one step. 27 Are you suggesting -- and maybe I read this 28 wrong -- are you suggesting that in the current rates of 302 ENERGY PROBE, Presentation 1 the utility, an electrical utility, there is a 2 reflection of the capital expenditure of the utility for 3 a given year as it would be expensed? Is this what your 4 comments refer to? 5 MR. ADAMS: That's right. There is no debt. 6 The utility doesn't have any debt. It is making these 7 long-term investments. They are paying cash at a 8 current rate. 9 We feel like we are in a -- when we have been 10 looking through the materials and trying to understand 11 this case and trying to express ourselves, we have been 12 caught in this kind of Alice-in-Wonderland world where 13 we really fundamentally see something very strange here 14 that is quite unusual. The way the municipal utilities 15 conducted their business previously is quite different 16 than the way we are accustomed to thinking about 17 utilities and the cash that they have and the lack of 18 debt is I think a signal of how different they really 19 are. 20 The normal utility has a substantial amount of 21 debt and that is efficient and appropriate because they 22 are making long-term investments. 23 MEMBER VLAHOS: So when I sought authorization 24 from Ontario Hydro, the previous regulator, if I'm a 25 utility, then I would ask that my capital expenditure, 26 whether it is in a forward test year or historical year, 27 those would be immediately recognized in the rates that 28 I am going to charge? 303 ENERGY PROBE, Presentation 1 MR. ADAMS: That is our understanding. 2 MEMBER VLAHOS: I'm sorry. Continue. 3 MR. ADAMS: What this has done is created, in 4 the municipal utility sector, a substantial stranded 5 benefit. We have a whole bunch of future benefits that 6 have been paid upfront, whereas in the old Ontario Hydro 7 there was the opposite case, right? We got a huge 8 leverage, like an infinite leverage, right, because they 9 have debt financed absolutely everything. 10 The absolute flip side of that is the 11 municipal utilities which paid cash money for these 12 long-term investments. 13 So we have developed a proposal, an 14 alternative procedure, for setting the initial 15 distribution rate requirement that accomplishes I think 16 the objectives that we think are appropriate in this 17 case, that the distribution utilities are on a level 18 playing field, that the consumer -- both the ultimate 19 customer and the utility see normalized rates and see 20 the function of the market-based rate of return as their 21 rates are being calculated this year and in 22 forward-going years. There is elimination of the double 23 payment problem where ratepayers who have already paid 24 for all these assets. 25 These were co-ops. They were non 26 investor-owned utilities. The municipalities didn't put 27 a dollar into these utilities. The assignment of the 28 value of the utility to the municipality is a new 304 ENERGY PROBE, Presentation 1 phenomena. Historically of course there was just -- 2 all the capital was from the customer. 3 So our proposal eliminates the double payment 4 issue and ratepayers get an itemized reduction to their 5 normalized rate, which declines over time. It allows 6 the utilities -- and I think this is a key point -- it 7 allows the utilities to make a fair rate of return on 8 all new investment when there is -- as we normalize and 9 rationalize the electricity sector. They have a normal 10 business structure under normal regulation. We expect 11 them to be partially debt financing, partially equity 12 financing their long-term investments, and that debt and 13 equity becomes the basis for a market-based rate of 14 return. 15 Finally, the ratepayers, under our proposal, 16 are spared rate shock because what we have done is we 17 have eliminated the double payment and the double 18 counting. 19 The formula has these 12 parts. It is hard to 20 do arithmetic standing up. 21 The formula has credits and debits. It is 22 probably just easiest, rather than speaking to the 23 record, to just refer to the formula that is in the 24 presentation. 25 In order to ensure that ratepayers receive a 26 proper return on the assets they have already paid for, 27 it would be necessary to track those assets and related 28 accumulated depreciation until those assets are fully 305 ENERGY PROBE, Presentation 1 depreciated. Utility financed assets would be tracked 2 separately. 3 If this is considered to be an unbearable 4 transaction cost, we suggest that a simplifying 5 assumption that might be appropriate is that all 6 ratepayer financed rate base be depreciated on a 7 straight line basis on the basis of its averaged 8 depreciation life, perhaps ten years or something else 9 that would be suitable. 10 This is another unusual aspect of our 11 submissions. We think that the net cash and marketable 12 securities of these utilities, in excess of their 13 working capital requirements, the billion dollars in 14 cash that is sitting there that has all been paid for by 15 their customers, that is customer money that is 16 effectively in a custodial relationship in the hands of 17 the utility. 18 That cash ought to be returned to ratepayers, 19 and our formula achieves that. It suggests that the 20 cash rebate be spread over a number of years rather than 21 a lump sum payment. 22 The market-based rate of return on ratepayer 23 funded assets and their depreciation should be an 24 itemized reduction on customers' bills, so customers can 25 see the rebate and also see the market-based rate of 26 return on their own assets decline as their assets 27 depreciate. 28 The new investment starts to dominate the 306 ENERGY PROBE, Presentation 1 customers' ultimate bill. 2 Our proposal will not leave municipalities 3 with worthless utilities, nor will it create a liquidity 4 crisis. Municipalities and potential investors will 5 know what their normalized rates are, as well as what 6 portion of rates in the initial years they are obligated 7 to rebate to ratepayers. 8 Utility owners still retain ownership of 9 unencumbered assets and a fair rate of return on new 10 directly invested capital, and additional profits 11 accruing from the efficiencies gained, according to the 12 price cap formula which we endorse. 13 There will be fairness amongst utilities and 14 municipalities, and investors can make decisions with 15 certainty. 16 In a discussion about market-based rate of 17 return, there has been some question about whether in 18 the case of the utility's sale the market-based rate of 19 return should be based on the selling price of the LDC. 20 We disapprove of this approach. We consider 21 it a circular argument. If the price is bid up at some 22 very high level, there is effectively no limit to how 23 high rates could go under such a circular position. 24 The argument has been made by some of the 25 participants, some of the utility participants, 26 particularly the Power/Budd group, that reducing the 27 market-based rate of return -- initially, their 28 criticism was directed at Board staff proposal related 307 ENERGY PROBE, Presentation 1 to contributions in aid of construction. 2 Their argument would apply with much greater 3 force to our proposal for eliminating both the 4 contributions and retained earnings from the 5 calculations. 6 The argument has been put that reducing that 7 market-based rate of return hurts the overall 8 restructuring of the electricity sector in the Ontario 9 government. They even make the argument that ratepayers 10 are harmed because of the effect of reducing PILS and 11 increasing the residual stranded debt of Ontario Hydro. 12 We characterize this as the "Canadian Tire 13 money" argument. Of every dollar paid by the ratepayer 14 towards market-based rate of return, only between 14 15 cents and 22 cents, depending on the deemed capital 16 structure, goes back towards PILS, thereby reducing the 17 CTC. 18 This is like saying that Canadian Tire could 19 jack up its prices, but the customer is better off 20 because they get more Canadian Tire money for their 21 purchases. Basically, we think that that approach 22 defies logic. 23 At this point, I want to leave as much time as 24 possible for the queries of the Panel, if you have any. 25 I can go on, if you want, but I am more interested in 26 your questions than me reading this stuff. 27 THE PRESIDING MEMBER: I have a question. I 28 am trying to follow it. 308 Energy Probe 1 Utilities in the past had rate bases, rate 2 bases being funded by contributions in aid, debt and 3 retained surplus earnings, whatever you want to call 4 them. 5 From that, there is a depreciation from that 6 rate base, and then I believe Ontario Hydro allowed some 7 sort of return, whether it was calculated as a 8 percentage return or whether it was calculated as a 9 working capital allowance. So you have sort of net 10 cash, and that is all being plowed back. 11 Is that the model you are equating it to? 12 MR. ADAMS: The only departure I would make is 13 that, for all intents and purposes, my understanding is 14 that the municipal utilities had virtually no debt. 15 But in every other respect, I think I totally 16 agree with you. 17 THE PRESIDING MEMBER: Some of them did have a 18 little debt, I believe. 19 MR. ADAMS: Yes. 20 THE PRESIDING MEMBER: I believe Toronto Hydro 21 is an example of one which had some debt. 22 MR. ADAMS: Yes. That is a confusing 23 situation. Toronto Hydro had -- we are speaking of the 24 old Toronto Hydro. 25 THE PRESIDING MEMBER: Yes, the City of 26 Toronto. 27 MR. ADAMS: The City of Toronto Hydro. 28 They had some very large amount of cash, in 309 Energy Probe 1 excess of $200 million, and they also had some debt; 2 approximately $50 million at the end of 1997, just at 3 their amalgamation point. It was close to the final 4 book before their amalgamation. 5 The debt is almost kind of a conceptual debt 6 at that point. 7 THE PRESIDING MEMBER: But basically, as I 8 understand what you are saying, the depreciation they 9 were collecting from the rate base, which included 10 contributed capital in some cases, and the surplus or 11 difference between rates and operating costs. That was 12 what they funded their capital from. 13 MR. ADAMS: I am not sure how depreciation was 14 treated in their former ratemaking process. It is not 15 clear to me that there was a reflection of depreciation 16 in the determination of rates. 17 THE PRESIDING MEMBER: I was just trying to 18 understand the model you were talking about. 19 If I took that analogy to a gas company, it 20 would be the same as the gas company that took no 21 dividends but reinvested all its earnings and its 22 depreciation in the new capital investment. 23 MR. ADAMS: That's correct. 24 THE PRESIDING MEMBER: And the amount of 25 capital they invested was capped, so to speak, by that 26 availability of cash. 27 MR. ADAMS: Yes. The only addition I would 28 make is that the investment was made without the benefit 310 Energy Probe 1 of debt. 2 THE PRESIDING MEMBER: Okay. 3 MR. ADAMS: So they were making the 4 investments out of retained earnings or customer 5 contributed capital, in one form or another. 6 THE PRESIDING MEMBER: I just wanted to 7 understand what you were describing. 8 MEMBER VLAHOS: I am happy you went first. 9 I want to follow up, Mr. Adams or Mr. Hilson, 10 with an analogy to gas so we can understand it. You can 11 appreciate that our experience is mostly with gas when 12 it comes to rate of regulation. 13 Just to follow up on Mr. Dominy's questions: 14 The fact that the electrical system has not paid 15 dividends to its owners, it used that cash to expand and 16 therefore it was not as safe for the utility to raise 17 debt. 18 MR. ADAMS: Yes. 19 MEMBER VLAHOS: So had the utility paid 20 dividends, then it would have raised debt. 21 MR. ADAMS: No. They could have paid 22 dividends without raising any debt. They could have 23 paid dividends out of their billion dollars in cash. 24 MEMBER VLAHOS: You are assuming that that 25 would be enough, that whatever they have now they could 26 have -- let me backtrack. 27 In a typical gas case you have your capital 28 and it is funded by equity, that is the owner's 311 Energy Probe 1 contribution, and then you have your earnings and then 2 you can choose to send it back to the owner as a 3 dividend or you can keep it in the company. In addition 4 to that you have debt that you raise in order to finance 5 your capital expenditures. So we can follow that. 6 So what you are saying is happening here is 7 that because there was no dividend there was no reason 8 to raise debt? 9 MR. ADAMS: That's correct. 10 MEMBER VLAHOS: Okay. When Ontario Hydro 11 regulated the municipal systems, can you help us as to 12 what formula they applied in order to set rates? 13 MR. ADAMS: We just know on a net basis what 14 happened. There are people who understand these things 15 much -- the history of how the rates were formed much 16 better than we do. 17 MEMBER VLAHOS: All right. But what is your 18 understanding if a system applied in October or November 19 to get its new rates for January 1st, what kind of 20 information would it supply and what kind of a decision 21 would Ontario Hydro make? Based on what information? 22 Can you help us with that? If not, that's 23 fine. 24 --- Pause 25 MR. ADAMS: All we can help with is the kind 26 of external view that whatever the mechanism was for 27 calculation of the rates, the rate was sufficient on 28 average for the utilities to fund their capital needs 312 Energy Probe 1 out of current revenues. 2 MEMBER VLAHOS: What you are also saying is 3 that they in fact had more than that because they had a 4 cash surplus -- 5 MR. ADAMS: That's right. 6 MEMBER VLAHOS: -- that is accumulated? 7 MR. ADAMS: That's correct. 8 Some utilities effectively dividended, using 9 the term loosely, some of that money back to their 10 customers. For example, Nepean Hydro ran a negative 11 rate of return for a period of years which would have 12 had the effect of drawing down their cash. 13 MEMBER VLAHOS: So what your table now 14 proposes to do is try to undo this. You don't want to 15 enter into a PBR or into a rate-making for the electric 16 utility where the utility was able to take back a dollar 17 for a dollar that was spent for the current year. 18 It looks like I have it, Mr. Adams, have I? 19 MR. ADAMS: Yes. 20 MEMBER VLAHOS: So what you want to do is you 21 are going to go back and rewrite history, if you like. 22 Forgive the -- I will use that term loosely. 23 MR. ADAMS: We want to adjust the starting 24 point. 25 MEMBER VLAHOS: Let me rephrase that. Okay. 26 What you are going to do is you are going to 27 put it on the same footing as a typical regulated, 28 private regulated utility and say, "Well, you can now 313 Energy Probe 1 recover in year one your $300 million you spend in year 2 one", because that is what is reflected in their rates. 3 Is that what you are telling me? 4 MR. ADAMS: That's correct. 5 MEMBER VLAHOS: So are going back now in 6 history trying to undo this. Is this what Table 1 does? 7 MR. ADAMS: What Table 1 does is try to look 8 at the starting point from where PBR will take off and 9 say what we had -- where we came from historically is 10 not the same structure as where we are going to in the 11 future, and if we just take the existing rate and we add 12 market-based rate of return on top of it, what we have 13 done is we have double counted a chunk of the existing 14 rate, or all of the market-based rate of return 15 depending on the assumptions. 16 MEMBER VLAHOS: What you are saying, as I 17 understand what you are saying, is you shouldn't take 18 the rate as a starting point and add market-based rate 19 of return. You should take the rate base, the cost of 20 service, add market-based rate of return and see what 21 the rate is? 22 MR. ADAMS: Yes. Yes. 23 MEMBER VLAHOS: As opposed to adding onto the 24 existing rate another factor? 25 MR. ADAMS: Exactly. 26 MEMBER VLAHOS: So you want to revise the 27 rates as a starting point before we start applying all 28 those new adjustments? 314 Energy Probe 1 MR. ADAMS: That is the purpose of the 2 formula. 3 MEMBER VLAHOS: Okay. Are you allowing for a 4 foregone dividend that would have been payable in a 5 private sector utility? 6 MR. ADAMS: That foregone dividend is in the 7 market-base rate of return. 8 MEMBER VLAHOS: Going forward. 9 MR. ADAMS: Going forward -- 10 MEMBER VLAHOS: I'm talking about going 11 backwards. 12 If we are going to adjust rates to put them on 13 the same footing as a commercial utility -- I'm sorry, a 14 utility on a commercial footing as, say, Union Gas or 15 Consumers Gas, I just am just wondering what your 16 assumption is about dividends which were not paid in the 17 past. Or do you just let that stand, bygones are 18 bygones? 19 --- Pause 20 MR. ADAMS: Do you still want an answer? 21 MEMBER VLAHOS: I'm sorry, is it yours or 22 hers? 23 Mr. Hilson? 24 MR. HILSON: Yes. Whether or not it was in -- 25 whatever your assumption was in terms of return on 26 capital, it is not really -- the MBRR would count it 27 once. I mean, the assumption of a proper dividend is in 28 the market-based rate of return. 315 Energy Probe 1 What is in the cost of service should be the 2 depreciation or, I guess, allocation of capital 3 required. That is what we are doing, is putting in the 4 depreciation which corresponds to the rate base used for 5 the market-based rate of return. 6 So rather than current year capital spending, 7 which is, like you said, allowing the company to recover 8 all their capital in year one plus earn a return on it. 9 MEMBER VLAHOS: Are you worried about just the 10 one year when you are setting rates that it does reflect 11 100 per cent recovery of the capital spending for that 12 one year or are you going back over history? 13 MR. HILSON: I don't think it matters what the 14 history was. We are saying that in order to apply the 15 market-based rate of return you have to have a capital 16 recovery allocation that corresponds to that 17 market-based rate of return, meaning the depreciation on 18 the rate base versus current year capital requirements 19 which are generally much higher due to utility growth 20 and inflation. 21 MEMBER VLAHOS: You will excuse that my 22 questions are very basic because I have not read this 23 anywhere. I have not come across it. I went through 24 the transcripts and can you help me, was this aired 25 before and was it commented upon by anybody? 26 MR. HILSON: We brought up this issue of 27 double counting. Dr. Cronin, I believe, asked us at the 28 technical conference. 316 Energy Probe 1 But in terms of fleshing it out, we have been 2 developing it over the last couple of weeks I guess. 3 MEMBER VLAHOS: So that's the first time it 4 appears in the form that it is? 5 MR. ADAMS: Well, the presentation at the 6 technical conference was really on this point. We made 7 a written presentation and an oral presentation and 8 responded to questions and the focus of our attention, 9 at that time, was the same issues we are bringing here: 10 the double payment and double counting. 11 MEMBER VLAHOS: I also recall that you were 12 starting with a zero rate base. 13 Is that a different -- is that a change of 14 your thinking? 15 MR. HILSON: No, but -- I guess the point is 16 that there's two distinct issues: what the rate base 17 should be or who should be entitled to the return on the 18 existing rate base, and how to set the opening revenue 19 requirements. They are two distinct issues. Both with 20 a large rate impact. 21 MEMBER VLAHOS: Okay. And you are, still, I 22 guess, asking the first issues; and that is the rate 23 base ought to be zero? 24 MR. HILSON: Yes. And our formula does that 25 in -- at least initially. 26 MEMBER VLAHOS: Just one last question, 27 gentlemen. 28 Mr. Adams, you have been involved with this, 317 Energy Probe 1 as someone called, "revolution of the industry". Do you 2 think that government had this in mind? 3 MR. ADAMS: We are pretty sure that nobody in 4 -- nobody that we can see in the official 5 decision-making apparatus behind Bill 35 and the White 6 Paper and the financial restructuring of Ontario Hydro 7 understood how the municipal utilities functioned as 8 businesses and the nature of their assets, their capital 9 and their rates. 10 My kind of academic suspicion is that the only 11 person, so far, in an official capacity, besides the 12 municipal unities, that really understood what was going 13 on was Mort Strong. He had a restructuring plan, in 14 1993, that dealt with this issue. 15 MEMBER VLAHOS: Thank you. 16 If I can just, then, ask some of the questions 17 that I had on your previous submission and see if those 18 have been answered. So just give me a second. 19 --- Pause 20 MEMBER VLAHOS: The formula that you made 21 today, which I believe was the first time it was brought 22 up, and that was, in case of a sale, what ought to be 23 the selling price, what ought to be the value to be 24 recognized in the rate base moving forward. And I 25 wonder if that's an issue for this proceeding or not? I 26 don't think it is an issue here. Is it mentioned in the 27 Rate Handbook? 28 MR. ADAMS: It's not mentioned in the Rate 318 Energy Probe 1 Handbook, although it was mentioned in several of the 2 submissions of the municipal utilities. 3 MEMBER VLAHOS: But I believe there is 4 another -- 5 --- Pause 6 MEMBER VLAHOS: I'm just trying to be of 7 assistance, Mr. Adams. 8 I believe that that issue may be coming up in 9 a different process. 10 MR. ADAMS: You are quite right, it was the 11 only reason we referred to it, and we did when we were 12 testifying, as well, at the technical conference; it was 13 because it's been broached by other intervenors. 14 MEMBER VLAHOS: Thank you. 15 Let me just go back to my old notes, now. 16 --- Pause 17 MEMBER VLAHOS: I guess my colleagues can ask 18 this question, then. 19 THE PRESIDING MEMBER: I was going to ask a 20 question on that, with regard to the supplements to the 21 Ontario Energy Board staff Handbook, which I believe was 22 issued August the 12th, and I believe Ms Kwik might be 23 able to -- Ms Kwik will be able to help me on this. 24 But in that, I understand that they talk about 25 how the market-based rate of return is calculated, and 26 in that they talk about the rate base being determined 27 by, I assume it's the net net book value, plus an 28 adjustment for working capital, which I believe is, in 319 Energy Probe 1 the extent of the default, is 15 per cent of the -- 2 there's a term in there. And then they said, the 3 additional revenue requirement to move to market-based 4 rate of return is -- market-based return -- there's a 5 formula -- minus what was earned or allowed to be 6 earned on the 1999 rate base. So the increment is added 7 not the total is added. Is that correct, Ms Kwik? 8 MS KWIK: That's correct, Mr. Chair. 9 THE PRESIDING MEMBER: So that the adjustment 10 that's made to the rates is really what additional 11 earnings would be required by the utility to keep their 12 market-based rate of return compared to what was allowed 13 in this existing rate. Is that a fair statement? 14 MS KWIK: That's right, Mr. Chair. 15 THE PRESIDING MEMBER: I just wondered whether 16 that supplement has been was available to you? 17 MR. HILSON: That's correct. I guess the 18 problem is that the percentage return on equity that is, 19 I believe, in that formula is on the entire net book 20 value -- or the entire equity in the company; whereas 21 -- so you are only partially counting for that when you 22 -- because of the percentage equity in the formula. I 23 guess -- like, assuming there's -- you know, whatever 24 return on equity is put in that formula, it's not going 25 to completely cover the problem. 26 THE PRESIDING MEMBER: I just wanted to make 27 sure that you were aware of the mechanics that Board 28 staff has proposed in its Handbook that issued the 320 Energy Probe 1 supplement which describes how the proposal is expected 2 to work. 3 MR. HILSON: Yes, that would mean that, like I 4 said, 40 -- whatever percentage equity in that formula, 5 you are going to account for that percentage of the 6 problem, but not the entire problem. 7 MEMBER ZERKER: Let's take it in another 8 direction. 9 First of all, I looked at your Table 1 and 10 tried, at lunch time, to do some numbers. I can't do 11 them without the (n-1), can I? Have you provided (n-1)? 12 There's no (n-1) in your table, is there? Like it would 13 be if the weighted average of fixed assets would be 19 14 years. Am I wrong about that? 15 MR. HILSON: I'm sorry. Are you wondering why 16 it's (n-1) instead of (n)? 17 MEMBER ZERKER: No; I know why it's (n-1) but 18 I don't -- I'm asking whether or not I have the 19 information for (n-1). 20 MR. HILSON: Yes, because (n) is in the table. 21 So (n-1) -- like, if (n) is 20, then (n-1) will be 19. 22 MEMBER ZERKER: That's right. 23 But would you then say that the year and the 24 (i) are the same as (n)? 25 MR. HILSON: The (g) is the average growth 26 rate of the utility, so it's -- 27 MEMBER ZERKER: The same. 28 MR. HILSON: Yes, so it would stay and the 321 Energy Probe 1 same and -- 2 MEMBER ZERKER: And (i) would be the same? 3 MR. HILSON: And (i) would be the same. 4 MEMBER ZERKER: All right. Well, see, that's 5 not a multiple. Obviously, you have done the 6 calculations. I just found I didn't have the -- I 7 didn't think I had the information to be able to do it 8 myself. But, anyways, let's go on to some other things 9 that -- 10 About the cash and the marketable securities 11 that the MEUs hold, you suggested that they ought to be 12 given back to the ratepayers over a period of years. 13 Right? 14 MR. ADAMS: That's where the money came from 15 and that's where it should return. 16 MEMBER ZERKER: In a sense though, the 17 ratepayers have become responsible for paying off the 18 debt that Hydro has accumulated, right, through the 19 municipalities and their rates and one way or another 20 the PIL really still comes out of the ratepayers' 21 pockets one way or another, doesn't it? 22 MR. ADAMS: Assuming no taxpayer bailout, but, 23 yes. 24 MEMBER ZERKER: I assume that. 25 So is there an alternative in your view that 26 would make sense that that money which might have gone 27 initially and through all those years to paying down 28 some of the debt that has accumulated, that in fact it 322 Energy Probe 1 should just go back to paying down the debt that we are 2 all paying interest on? 3 MR. ADAMS: This actually comes back -- your 4 remark is very similar to Mr. Vlahos' question about who 5 understood what in this restructuring. 6 I think the logic of using stranded benefits 7 offsets stranded costs. If government had seen that and 8 perhaps if some of the intervenors in that process had 9 understood better what was going on we could have made 10 them see it, but the logic is impeccable, to use 11 stranded benefits to offset stranded costs. 12 MEMBER ZERKER: My question then is which way 13 are the ratepayers better off? I am not saying that 14 that is necessarily what the government would allow the 15 Board to do, but if it was open ended which way would 16 the ratepayers be better off? 17 Would they be better off by getting a 18 kickback, some kickback over a period of years as a 19 result of the cash by your proposal, or would we all be 20 better off if we stopped having to have a type of 21 embedded system? 22 MR. ADAMS: I think you can do it either way. 23 So long as the benefits stay within the electricity 24 system we are pretty indifferent as to which of those 25 proposals we actually pursue. 26 But where we are worse off is if we rely on 27 the clawback of the PILs which is getting 14 or 22 cents 28 on the dollar and allowing the rest of that money to 323 Energy Probe 1 escape from the system. That makes ratepayers much 2 worse off. 3 MEMBER ZERKER: I agree with that. Also there 4 is a lot more opportunity for gaming and making 5 different forms of corporate adjustments that would not 6 end up where one ought to see them go. 7 Whereas if you did this it would be a direct 8 benefit, would it not? 9 MR. ADAMS: That's the idea. That's exactly 10 what we want to achieve. 11 MEMBER ZERKER: I am not sure and perhaps I 12 misread the Draft Handbook, but down in your discussion 13 about price cap mechanism you say that the proposal 14 seems that the utilities will rely on contributed 15 capital to the same degree as they have in the past. Is 16 that an assumption that is inherent in the Handbook? 17 MR. ADAMS: We had this discussion, Ms Kwik 18 and ourselves, at the conclusion of our questions on the 19 23rd of September. 20 MEMBER ZERKER: I don't remember it in the 21 transcripts. 22 MR. ADAMS: Perhaps I should not rely on my 23 own member, but invite Ms Kwik. 24 MS KWIK: I hope that's what I said. 25 It's not that we are proposing in the Handbook 26 that that's what he is told he is due, but depending on 27 the limitations in the system expansion guidelines and 28 contributed capital they still will be using contributed 324 Energy Probe 1 capital for funding. 2 MEMBER ZERKER: But not necessarily in the 3 same principle as they had in the past or would they? 4 MS KWIK: Well, we asked Nepean Hydro whether 5 their policy on contributed capital would change in 6 consideration of the fact that they no longer will earn 7 a rate of return on it in the future. The indication 8 from Mr. Emmet was that, yes, they would plan 9 differently. 10 MEMBER ZERKER: Well then it would be 11 different. 12 MS KWIK: In his case. 13 MR. ADAMS: The point of our concern was that 14 since the PBR Handbook starts with the existing rate, 15 it's actually just a portion -- for some utilities it's 16 just a portion of their total gross revenues comes 17 through rates. Another portion of it comes through 18 contributed capital. 19 So for the utility to carry forward on the 20 same basis there is an implicit assumption about the 21 policies with regard to contribution in aid following 22 forward. 23 MEMBER ZERKER: But it's not explicit. 24 MR. ADAMS: But it is not explicit, that's 25 correct. 26 MEMBER ZERKER: Then you go on to say that you 27 would propose for the Board to develop uniform policies 28 about contributive capital that would apply across the 325 Energy Probe 1 board. 2 The reason I made a note of that is because it 3 raises the problem of the Board becoming a micro-manager 4 of utilities that are commercialized. I think that 5 that's something I would like to raise with you because 6 it is one of your proposals here and the Board has to 7 consider where it should draw the line and where it 8 shouldn't draw the line. 9 MR. ADAMS: We are very sensitive to the 10 concern about micro-management. We do not want to see 11 the Board become a micro-manager. It's not in the 12 public interest, but monopolies have to be controlled 13 and particularly with regard to the revenue. 14 They have all kinds of -- the revenues of the 15 monopoly utilities, derived from their monopoly service, 16 relates not just to rates, but contributions in aid and 17 other special payments that they might require of their 18 customers for different services. 19 So we think that the Board has a legitimate 20 interest and concern. The consumer needs to be 21 protected with regard to all of those monopoly services. 22 Contributions in aid is inherent to the monopoly. 23 There may be mechanisms to protect the 24 consumer interest by ensuring open season, allowing 25 customers to construct their own and ensure that those 26 assets are out of rate base. There are mechanisms for 27 dealing with it, but we are concerned about all elements 28 of monopoly revenue. 326 Energy Probe 1 MEMBER ZERKER: But I get the sense that you 2 are proscribing by a uniform policy of proscribing 3 something that people are complaining about now, which 4 is one size fits all and one size, we are reminded again 5 and again, cannot fit all by all kinds of intervenors 6 that have come here. 7 So if we are treading into the next phase with 8 a uniform policy, we are making that assumption it seems 9 to me, or am I wrong? 10 MR. ADAMS: No, you are not wrong. We are to 11 consider also the intended effects of the price cap 12 mechanism that you are creating. The price cap 13 mechanism relates to rates which is just one piece of 14 the utility business. 15 There are other parts of the utility business 16 where there is the opportunity for mischief. We are not 17 alleging mischief, but there is an incentive for 18 utilities to find other ways to raise revenue. One part 19 is capped and one part -- we want all the monopoly 20 revenues to be regulated. 21 MEMBER ZERKER: Yes, you said that somewhere 22 else and listed some of the different areas which you 23 want regulated. It's hard to be clear on whether or not 24 the authority is there to regulate unregulated business. 25 MR. ADAMS: We were just talking about 26 monopoly business. 27 MEMBER ZERKER: I know. Okay. 28 Now, the next thing that I want to talk about 327 Energy Probe 1 is your objective to harmonizing rates. It seems to me 2 that on the one hand you recognize that contributed 3 capital has permitted some consumers, some ratepayers, 4 to benefit from lower rates by virtue of the fact that 5 the direct consumers of the facilities paid for their 6 share directly. I think you take that as a given within 7 some of your arguments about contributed capital, that 8 some ratepayers benefitted from contributed capital, and 9 that all ratepayers, in one way or another, paid for all 10 that capital. Right? 11 MR. ADAMS: Yes, that's correct. 12 MEMBER ZERKER: So if you do that, then why 13 are you objecting to those who have benefitted from 14 lower rates and in fact, in many cases, would have been 15 the same kind of -- for the same kind of reasons are now 16 having to harmonize their rates with some who did not 17 received that benefit? 18 MR. ADAMS: It's just a fairness issue. 19 MEMBER ZERKER: That is exactly my point. I 20 think it is a fairness issue. 21 MR. ADAMS: You have some customers that -- 22 let's take the example of a utility that had a high 23 amount of contributed capital and low distribution 24 margins being merged with another utility that had 25 similar growth rates but no contributions-in-aid policy 26 and higher rates. 27 MEMBER ZERKER: Right. 28 MR. ADAMS: Right? 328 Energy Probe 1 These customers have already paid. The 2 customer who paid the contributions in aid -- 3 MEMBER ZERKER: So they both always -- what 4 you are saying is they both pay, only the one who have 5 had the lower rates are the ones who have benefitted 6 from contributed capital, individuals -- 7 MR. ADAMS: Utilities that had a 8 contributions-in-aid policy, the reason they had them 9 was so that customer -- the utilities were operated as a 10 co-op. The co-op had built up equity. New customers 11 came in with high marginal costs. If the utility was 12 going to service those new customers, it was going to 13 have to raise rates for existing customers. 14 Rather than do that, the utilities 15 introduced -- some utilities introduced a 16 contributions-in-aid policy so that the new entrants 17 were not free riders on the existing customers, 18 protecting the interests of the existing customers. 19 So in the low rate utilities you have historic 20 customers who paid a long time ago and paid the cost of 21 their capital that they are using and they see low 22 rates. You also have new customers that see low rates 23 but have paid substantial contributions in aid into the 24 co-op to get, you know, admission to the co-op, right? 25 So you have some customers that have paid a lot, some 26 that have paid a little, but rates are low. 27 If you amalgamate with a high-cost utility, 28 either one that doesn't have a contributions-in-aid 329 Energy Probe 1 policy or one that happens to be very inefficient, then 2 you end up with a penalty against the customers who have 3 contributions in aid or who were the beneficiaries of 4 efficient utilities. So they see higher rates, not 5 because of anything they did. 6 There is no cost basis to justify increasing 7 the rates for those customers in a low rate 8 jurisdiction. 9 MEMBER ZERKER: Would you be saying that same 10 thing if you assume that the high rate utility, 11 customers of the utility, is as efficient as the one 12 with the low rate? Do you say that as well? 13 MR. ADAMS: A conceptual example that fits 14 your question is the situation where you have an urban 15 utility that is efficiently run but because of density 16 has a low distribution margin and then a mostly rural or 17 low density and they are amalgamating similar -- like, 18 absolute efficiency but of course a higher distribution 19 margin in the low density regime. 20 But the benefit of our proposal is that the 21 benefit of the existing system, the benefit or the cost 22 of the existing system, stays with the jurisdiction that 23 created it. So in the instance of an urban and rural 24 amalgamation, the benefit of the urban efficiency isn't 25 just transferred to customers who impose higher costs on 26 their system. 27 MEMBER ZERKER: I will have to think about 28 that. 330 Energy Probe 1 --- Pause 2 THE PRESIDING MEMBER: Mr. Adams, I was just 3 wondering, were there any other points you wanted to 4 make or can we continue with the questions? 5 MR. ADAMS: No. Really your questions are 6 much more important than the points I would add. 7 THE PRESIDING MEMBER: Then carry on, 8 Dr. Zerker. 9 MEMBER ZERKER: An example in the gas 10 instance, historically, of this problem of 11 harmonization, is Fort Francis. 12 MEMBER ZERKER: Fort Francis. 13 THE PRESIDING MEMBER: Are they actually on 14 the same rates, yet? Have they actually hit it yet? 15 MR. ADAMS: You are a much more careful reader 16 of the rate filings than I am and I can't remember. 17 THE PRESIDING MEMBER: I just wondered. I 18 know it was a -- that is an example of a low-cost 19 ratepayer being moved up to the higher cost of the 20 acquiring entity and, yes, I agree. 21 MEMBER ZERKER: Do you have any idea, if I go 22 to your page 4, when you are talking about -- that the 23 existing rates have to be adjusted before we start the 24 calculations. Obviously, you think it has to be 25 downward, right? 26 MR. ADAMS: Yes. 27 MEMBER ZERKER: Any idea how much or is there 28 any number? 331 Energy Probe 1 MR. ADAMS: We estimate that just to account 2 for the double-counting problem, not the double payments 3 but just for the double counting, is the 20 per cent 4 decrease -- 5 THE PRESIDING MEMBER: Could I interject here? 6 MR. ADAMS: -- which is the $600 million a 7 year. 8 THE PRESIDING MEMBER: I'm sorry. I'm having 9 a bit of trouble. If you could define the 10 double-counting problem for me, exactly what -- 11 MR. ADAMS: Yes. 12 The double counting is that if it had been a 13 normal utility the rates would not have recovered the 14 capital budget in each year, they would have recovered 15 the impact of the depreciation. 16 THE PRESIDING MEMBER: And the carrying costs. 17 MR. ADAMS: And the carrying costs. 18 So the existing rate contains a cost that 19 customers are bearing today in excess of the 20 depreciation and carrying costs that would have been 21 there had we had a normal rate structure. That is the 22 double counting. 23 THE PRESIDING MEMBER: My problem is the 24 following. Basically, what that statement says to me is 25 that the rates that exist included the capital budget as 26 part of the cost of service, as opposed to an 27 alternative which could be that the sum of the surplus 28 from the rates, less cost of service, plus the 332 Energy Probe 1 depreciation was sufficient funds to fund the capital 2 program. There are two different -- 3 MR. ADAMS: Those are the same things. 4 THE PRESIDING MEMBER: No, they are not. One 5 is -- sorry, I am really not trying to be 6 argumentative. I just want to understand it. 7 In a sense, there is some depreciation from a 8 past capital -- assuming depreciation is allowed. And 9 then there is the difference between what you have paid 10 in your rates and what is required to pay the bills of 11 the municipal utility, the surplus retained earnings. 12 The two of them, the depreciation plus the surplus, 13 create a cash pool which is then used to do something, 14 is allocated to different activities, one of which could 15 be the capital programs. 16 So that could be the source of funds. When 17 you go to next year, that capital is in the rate base 18 and it gets depreciation attached to it. 19 What I understand you to have said is that not 20 only did they have the whole of the capital put into the 21 year that was spent that year, but they also get 22 depreciation on it in that year. That is double 23 counting. 24 MR. HILSON: He may have said it, but he 25 didn't mean it. 26 THE PRESIDING MEMBER: I may have misheard it, 27 which is equally likely. 28 MR. HILSON: The double counting is basically 333 Energy Probe 1 the excess of the current year capital spending over top 2 of the depreciation on rate base, or assets in the 3 utility. 4 THE PRESIDING MEMBER: It's the surplus you 5 are talking about. In the case of a utility that is 6 funded through debt and equity, it might be the interest 7 plus the return. 8 MR. HILSON: Right. The market-based rate of 9 return reflects all of the return. So you are double 10 counting some of it in there. 11 The impact, because it is so capital intensive 12 -- I have seen net book value of assets in the 13 neighbourhood of $6 billion in 1996, with distribution 14 revenues of a little over a billion or $2.3 billion. 15 Because it is so capital intensive, we are talking about 16 the difference between say five or six, say $600 million 17 in annual spending on capital and say half of that, 18 $300 million in book depreciation, which should be in 19 the rates if you are going to add on a market-based rate 20 of return. 21 So $300 million on $1.2 or $1.3 billion is 22 over 20 per cent. This is not trivial. 23 THE PRESIDING MEMBER: In other words, you are 24 saying that the return they were earning was higher than 25 a normal market-based rate of return would have been. 26 MR. ADAMS: That's right. At the technical 27 conference -- I think we are trying to figure out why 28 we see this so differently relative to Board staff. 334 Energy Probe 1 Dr. Cronin made a statement that I think 2 reflects the difference in perspective. He said that 3 historically the distribution utilities were 4 undercharging for the service. I can understand how 5 that perspective arises. You look at traditional public 6 utilities versus private utilities and look at their 7 cost of capital; they don't pay dividends; they don't 8 pay taxes. In the United States, they get these 9 municipal bonds. 10 So it is clear that if you are going to make 11 an apples to apples comparison, you have to adjust the 12 costs. If you are trying to make efficiency 13 comparisons, which is Dr. Cronin's business, you adjust 14 the public utility cost to put it on the same basis as 15 the private utility. 16 He just brought -- I think he -- I shouldn't 17 suggest perspectives, but it looks to me as if he 18 brought that and just assumed that was happening with 19 our municipal utilities. There is quite a difference. 20 Our municipal utilities are not public 21 utilities in the sense that Ontario Hydro is a public 22 utility or the municipal distribution utilities in the 23 United States. They are really quite different legal 24 business animals. 25 MEMBER ZERKER: I want to ask about your 26 proposal about the Z-factor. 27 MEMBER VLAHOS: Could I just follow up on 28 that? 335 Energy Probe 1 MEMBER ZERKER: Yes, certainly. 2 MEMBER VLAHOS: There was some discussion, 3 Mr. Adams, about the treatment of depreciation by 4 Ontario Hydro. So depending on what the answer is, are 5 we talking about triple counting? 6 I understand your theorem about double 7 counting, in that you actually expense, if you like, 8 your capital expenditures, which is not the case with 9 the private utility. 10 To the extent that now you are expensing, to 11 the extent that it is recognized in your rates, but also 12 if you are allowed to add depreciation or convince the 13 regulator that you also have to get back some 14 depreciation expense, that is triple counting. Is that 15 right? 16 MR. ADAMS: If that happened, that would be an 17 instance of triple counting. 18 MEMBER VLAHOS: I think I will leave it at 19 that. 20 MEMBER ZERKER: On the Z-factor, I take your 21 point that private companies buy insurance for 22 protection. But would that include for you transition 23 costs? 24 This is rather an unusual situation, as you 25 know. You can't go out and take the private company and 26 say: Let's identify its costs with something that is 27 happening in the electricity industry. 28 MR. ADAMS: That is an inconsistency in our 336 Energy Probe 1 presentation. It is just a reflection that there is a 2 limit to how extreme we are prepared to be with regard 3 to this Z-factor issue. 4 You are quite right that implicit in our 5 position paper is an acceptance of a Z-factor, if you 6 want to call it that, for transition costs. There is a 7 judgment on what is the legitimate range of costs that 8 the LDC can bear. 9 --- Pause 10 MR. HILSON: I think, also, our comments on 11 transition costs were assuming that they were deemed 12 appropriate; that the Board should not be burdened with 13 a lot of regulatory time determining how 273 different 14 utilities should be able to recover different transition 15 costs, and therefore it should be just an allowance on 16 some sort of prudent formula basis. 17 I would agree. I guess we could take a 18 position that the utilities have enough money from 19 accumulated retained earnings to pay for transition 20 costs as well, but we are not taking that position. 21 MEMBER ZERKER: What would you propose, then? 22 Some kind of limited fund per customer basis or 23 consumption basis, something on that order, in order to 24 keep it simple? 25 MR. HILSON: Yes. It would be, I guess, 26 probably some sort of flat amount plus a fixed and 27 variable formula, depending on the size of the utility. 28 You could use customer numbers or something. I don't 337 Energy Probe 1 know. 2 MEMBER ZERKER: Here is something that you are 3 not going to answer to, but it does happen that when 4 extraordinary events occur, as they did in Quebec, to 5 electricity systems, taxpayers pay for it anyways, 6 because government then gets involved and has to bail 7 out or in one way or another assist the utility or 8 utilities, as the case may be -- in Ontario now -- 9 from extraordinary expenses. 10 MR. ADAMS: It is a matter of speculation. 11 But there were certainly some utilities in Ontario that 12 were hit as hard by the ice storm as utilities in 13 Quebec. 14 MEMBER ZERKER: Yes, there were. 15 MR. ADAMS: I would be surprised if any of 16 those utilities had to borrow to put their systems back 17 up. I bet they paid cash money for it. 18 MEMBER ZERKER: They were still under the 19 Hydro regime. 20 MR. ADAMS: Yes. 21 MEMBER ZERKER: So unless we looked closely we 22 wouldn't know whether or not it was the parent company 23 or the parent organization that was taking care of them, 24 or do you know that? No? 25 But I mean that's just an aside. Ratepayers 26 and taxpayers, we often have just a number of pockets 27 and in the case of extraordinary events we become hay 28 for them one way or another. 338 Energy Probe 1 MR. ADAMS: We made some more extensive 2 submissions in the technical conference about the 3 importance of distinguishing between the interests of 4 taxpayers and ratepayers and not confusing them. There 5 is a great risk in these debates to the interests -- 6 MEMBER ZERKER: I agree with that. 7 MR. ADAMS: -- of consumers if we just 8 kind of -- 9 MEMBER ZERKER: No, I agree with that. 10 MR. ADAMS: -- willy-nilly throw them away. 11 MEMBER ZERKER: This was an aside actually. I 12 didn't really -- 13 --- Pause 14 THE PRESIDING MEMBER: Mr. Vlahos? 15 MEMBER VLAHOS: Yes, thank you. 16 Gentlemen, just two or three more questions. 17 Just to finish this area about the cash 18 sitting in the drawers of municipalities. Since the 19 purpose of it, as now I understand from you gentlemen, 20 is to fund capital expansion, they are not really there 21 to be provided as dividends, it is there for a purpose, 22 according to your view? 23 MR. ADAMS: It's hard to understand what the 24 purpose is for accumulating such vast amounts of working 25 capital, multiples of the required need. I think it is 26 not really purposeful that generation of cash, it flowed 27 out of the institutional circumstances the utilities 28 found themselves in. 339 Energy Probe 1 MEMBER VLAHOS: But the prime purpose is to 2 continue to fund those capital expansions year after 3 year? 4 --- Pause 5 MR. HILSON: The whole purpose of a 6 market-based rate of return is to recover capital 7 investment, I guess on a deemed capital structured debt 8 and equity. The cash and securities that they have, 9 there is no direct linkage there, I don't think. 10 MEMBER VLAHOS: All right. Okay. I will 11 leave that area. 12 Just a few quick questions. I am going back 13 to your submission, not today's submission that you have 14 handed out. I don't know if you have a copy of it. You 15 don't have to turn it up, but if you do it would help. 16 --- Pause 17 MEMBER VLAHOS: On page 2 you are suggesting 18 that for the initial PBR period the equity component, 19 the common equity component ought to be 40 per cent as 20 opposed to what has been recommended in the Handbook. I 21 would just like to know whether the other parties 22 commented on that proposal of yours in the technical 23 conference. Did you get any support for that? 24 --- Pause 25 MR. HILSON: We don't think it has been 26 studied. We think intuitively that the range 35 to 27 50 per cent is too wide to account for differences in 28 risk among different sides of a utility and until we see 340 Energy Probe 1 some justification for -- supportable justification for 2 differences that in the first regime you would start out 3 with a common number amongst all. 4 MEMBER VLAHOS: So you would classify the 5 riskiness of the utility, whether it is small or large, 6 being the same? 7 MR. HILSON: I mean, there is going to be -- 8 we accept that there is some difference but that 15 per 9 cent is too wide a spread and that until we know what 10 the appropriate number is that is supportable you start 11 out with the same. 12 MEMBER VLAHOS: But you recognize that there 13 are differences in risk from one system to another and 14 since we don't recognize that risk to differentiate a 15 rate of return on common equity, then to the extent that 16 it has to be recognized in the thickness of the capital 17 structure you may be uncomfortable with a 15 per cent 18 spread, would you be comfortable with a 5 per cent 19 spread? 20 MR. HILSON: That sounds like what it would -- 21 if we took the time to look at the range across the 22 regulated utilities I think it would be a lot lower than 23 15 per cent, maybe perhaps 5 per cent. 24 MEMBER VLAHOS: Okay. 25 MR. ADAMS: One of the basic points that drove 26 our submission on that issue was the sense that risk for 27 regulated utilities is not necessarily a function of 28 size but rather a function of its revenue streams, that 341 Energy Probe 1 you could take a utility in Northern Ontario that serves 2 a mining community and their revenue stream long-term 3 might have a very different risk profile than a similar 4 sized utility in Southern Ontario serving a more 5 diversified economy. 6 MEMBER VLAHOS: Okay. Thank you for that. 7 A couple of more questions, Mr. Chairman. 8 Your discussion of the transition and 9 extraordinary event cost adjustments, which is part of 10 3.3.4, and also your discussion on the Z-factor, which 11 is paragraph 4.4, seems to me to be the same. Is that 12 the same discussion? 13 The transition and extraordinary event cost 14 adjustments, they are part of the Z-factor? 15 MR. HILSON: Yes. I think this is the same 16 question already raised and Tom acknowledged that there 17 is a bit of an inconsistency. 18 I guess what we are saying is that if 19 transition costs are to be awarded we don't want to see 20 that be the focus of lengthy proceedings and undue 21 regulatory time for all the utilities. 22 MEMBER VLAHOS: Okay. But the important 23 point, Mr. Hilson, here is, do I take your suggestion 24 that there ought to be a formula basis for the recovery 25 of transition costs to the extent that they are deferred 26 to apply also to all of the other items under the 27 Z-factor or is this specific to the transition costs? 28 MR. HILSON: No, just specific to the 342 Energy Probe 1 transition costs. 2 MEMBER VLAHOS: Okay. Thank you. 3 On the pricing flexibility -- and you had a 4 discussion with Dr. Zerker on that one -- you wish to 5 maintain the distinct rate classes in case of 6 amalgamation of two systems. Is that -- 7 MR. ADAMS: Yes. 8 MEMBER VLAHOS: Okay. My question is: For 9 how long? 10 --- Pause 11 MR. ADAMS: That's a hard one. 12 MEMBER VLAHOS: So why amalgamate? 13 MR. ADAMS: The reason to amalgamate is to 14 obtain efficiencies. 15 MEMBER VLAHOS: Strike that out. 16 I'm sorry. 17 MR. ADAMS: Amalgamation is legitimate. We 18 don't want to discourage amalgamation, but we are just 19 concerned about -- the focuses of amalgamation should be 20 on achieving efficiencies rather than simply 21 transferring costs. 22 MEMBER VLAHOS: Final two questions. 23 Under 5.4, remedial activity, that is page 3, 24 you are starting the sentence or paragraph by saying: 25 "Recognizing that the next PBR period 26 will include penalties..." (As read) 27 It sounds quite definitive. I just wondered 28 about the source of that. 343 Energy Probe 1 MR. HILSON: I would have to look it up, but 2 I'm pretty sure it is pretty definitive in the Handbook 3 that there will be some enforcement. 4 MR. ADAMS: We support penalties for failure 5 to achieve target. 6 MEMBER VLAHOS: Thank you. 7 The last question, gentlemen, is on the first 8 generation PBR, the annual filings. 9 You want the Board to require utilities to 10 accumulate and provide cost data for customer care, 11 metering and meter reading in anticipation of unbundling 12 those functions. 13 I guess given what is on our plate and yours, 14 is this something that perhaps can wait? 15 MR. ADAMS: In order -- the unbundling can 16 wait. Eventually, it's beneficial. And we do 17 appreciate the other priorities before the Board. But 18 in order for that unbundling process, eventually, to be 19 fruitful have those discussions run smoothly, the data 20 problems that we have seen in this PBR issue -- which 21 has been really immense and very, very challenging for 22 the intervenors and much more so, I think, for Board 23 staff -- we should solve that problem now. 24 MEMBER VLAHOS: Maybe I am going beyond my 25 depth there, Mr. Adams, but it is my read of it that the 26 proper accounting methodologies have been already, or 27 will be, set out in the infosystems accounts so that one 28 can sort of pick and choose as to what he service he 344 Energy Probe 1 wants to identify or what cost that is going to identify 2 with what service and you can sort of pick those things 3 out from the U.S. of A. universal accounts. I don't 4 know, maybe staff can correct me on this. Am I right on 5 this? 6 MS KWIK: I'm sorry, Mr. Vlahos, I don't 7 remember, so I can't comment. 8 MEMBER VLAHOS: That is a safe way out. 9 MR. ADAMS: The intention of the submission is 10 that we favour a move to unbundling of those 11 customer-care costs. We see them in gas, we see them in 12 electricity, and we want to make sure that they are 13 subject to as much competitive pressure as possible. 14 MEMBER VLAHOS: All right. Thank you. 15 Now, before your final submission, if you 16 intend to make one, you may wish to place a call to the 17 E.R.O.'s office and say whether this information will be 18 captured there. 19 MR. ADAMS: Are there any other matters that 20 the Board would like submissions from in any final 21 submission that we would be making? 22 THE PRESIDING MEMBER: I think, Mr. Adams, it 23 will be your choice of subjects that you wish to comment 24 on. But before we -- I believe Ms Kwik has a question 25 of clarification she wants to ask. 26 MS KWIK: Yes, I do. Thank you, Mr. Chair. 27 With regard to the billion dollars in cash and 28 marketable securities that are supposedly in the hands 345 Energy Probe 1 of the utilities, that would include their working 2 capital, both for distribution as well as commodity. Is 3 that right? 4 MR. ADAMS: I believe that's right. When we 5 are making our submissions on working capital -- or on 6 cash and securities, we don't want to drain the 7 utilities of their working cash. It's essential that 8 they have working cash to be able to function at 9 businesses. And one reason they are going to need 10 working cash may be for prudential requirements, for 11 trading as wholesale lots participants. 12 MS KWIK: Do you know what proportion of this 13 billion dollars is not surplus cash? 14 MR. ADAMS: We spoke to Dr. Cronin -- 15 --- Pause 16 MR. ADAMS: We are not able to quantify the 17 amount. But it appears that the cash available is of 18 the same order of magnitude, within a few hundred 19 million dollars, of their total annual costs. So the 20 excess amount of cash has to be very, very large, 21 perhaps 800 million, but we don't have a basis to make a 22 carefully advised estimate. 23 MS KWIK: Thank you. 24 THE PRESIDING MEMBER: Dr. Zerker has a 25 question. 26 MEMBER ZERKER: No, it's not a question. It's 27 a request. And I don't know if it's feasible. 28 If you take your -- if it's possible, for my 346 Energy Probe 1 benefit, to use the formula in your final submission, 2 using a hypothetical utility, like doing an MBA course, 3 or something -- that's the world I come from -- but 4 anyways, is it possible to do it that way so it would 5 illustrate, for us, more precisely what you have in 6 mind? If you can't do it, you know, that's fine. If 7 it's an overwhelming task, then forget it. But I just 8 wondered if it's possible to do it that way. 9 MR. ADAMS: Our collection of annual reports 10 is, I think in some respects, maybe better than the 11 Board's but still not adequate to the task that you have 12 put us to. We have least 1997 data on some utilities, 13 but the Board's materials is working with 1996. 14 MEMBER ZERKER: I was just thinking in terms 15 of a hypothetical case, you know. 16 MR. HILSON: Maybe you could -- I guess the 17 examples in the table are -- they were trying to be 18 hypothetical cases where you have a different portfolio 19 of assets, in terms of the length of useful life of the 20 assets in the utility and different growth rates of the 21 utility and even, you know, different inflation factors, 22 because if you want to go back 15 years, inflation was 23 lower. 24 MEMBER ZERKER: I'm talking about the proposed 25 revenue requirements formula. 26 MR. HILSON: Oh, I'm sorry. 27 MEMBER ZERKER: That's the one I'm talking 28 about. On page 6. 347 Energy Probe 1 MR. HILSON: Okay. I'm with you. Okay. 2 MEMBER ZERKER: Can you do that? 3 MR. HILSON: Yes. 4 MEMBER ZERKER: Okay. That would be 5 interesting. 6 MEMBER VLAHOS: Mr. Adams, Mr. Dominy just 7 pointed out to me that the uniform system of accounts, 8 believe it or not, and some of the things you are 9 talking about, they are included as separate line items, 10 so I still extend that invitation to you to be in touch 11 with the E.R.O. and see whether that -- the items you 12 are looking for, whether they will be captured in the 13 U.S. of A. and it's just a matter of when the Board will 14 order unbundling. Okay? 15 MR. ADAMS: Thank you. 16 THE PRESIDING MEMBER: Thank you very much, 17 Mr. Adams and Mr. Hilson. As you can see, it stimulated 18 a lot of discussion this afternoon, I would call it. 19 And thank you for your presentation. 20 MR. ADAMS: Thank you for the opportunity to 21 appear. 22 MR. HILSON: Thank you. 23 THE PRESIDING MEMBER: I know that we have 24 DTE/Probyn and Sault Ste. Marie as the next presenter. 25 I would ask if we could have five or 10 26 minutes' break just to get organized; I believe a couple 27 of people who have to do something. So we will come 28 back in 10 minutes and then we will carry on then. 348 1 --- Upon recessing at 1540 2 --- Upon resuming at 1556 3 THE PRESIDING MEMBER: Thank you for waiting. 4 I am sorry we are running a bit behind. 5 Mr. Allen? 6 MR. ALLEN: Yes. 7 THE PRESIDING MEMBER: It's yours. 8 PRESENTATION 9 MR. ALLEN: Thank you. 10 I would like to thank the Board for the 11 opportunity to present material on behalf of Sault Ste. 12 Marie. 13 First, I would like to introduce the people 14 who are sitting at the table. On your far right is 15 Clive Healey, who is the Manager of Administration from 16 Sault Ste. Marie PUC, Public Utilities. Next to Clive 17 is Daria Babaie, Vice-President with Probyn Energy 18 Solutions and at the far end of the table is Dr. Chester 19 Bolling who is a regulatory specialist with us. 20 First, I would like to start off with a very 21 quick outline of my background. I have about a dozen 22 years with Ontario Hydro and eight years with municipal 23 utility, the last six as the General Manager of 24 Scarborough Utilities, so the previous discussion that 25 Mr. Adams went on about is extremely familiar. 26 I would also like to note that both Mr. Healey 27 and Mr. Babaie have some commitments, flights and what 28 not, so they may have to excuse themselves part way 349 DTE/PROBYN, Presentation 1 through the presentation. They are going to stay as 2 long as they possibly can. 3 Our comments today on the Rate Handbook are 4 intended to provide that PBR provides strong initiatives 5 for utilities to continue to improve their efficiencies, 6 resulting in lower rates for customers and potentially 7 higher profits for shareholders, that we are looking for 8 fair and equitable unbundling of rates into distribution 9 and commodity components and further simplifying the 10 procedure to unbundle the existing rates and improve 11 accuracy. 12 We are looking for the market base rate of 13 return, as well as costs incurred by the utility for the 14 transition to the new market structure being 15 implemented. One of the key points we are trying to 16 raise is that there is a level playing field amongst all 17 the distribution utilities and, finally, that there is a 18 true incentive base regulation where utilities that have 19 good performance have the ability to be rewarded further 20 by improving their performance. 21 Our August 12 submission was in four different 22 areas and we will move into the rate adjusting mechanism 23 and the initial rates in a moment. Dr. Bolling will 24 handle that portion. 25 I want to sum up the service reliability 26 entities and customer service performance indicators 27 with really that there are six principles. We discussed 28 the detail at the technical conference and the detail we 350 DTE/PROBYN, Presentation 1 really intended to try to provide positive suggestions 2 to the Board on how to enhance what we are trying to 3 accomplish with each of those. 4 Really, the six principles that we have looked 5 at that need to be in place is that the utility must be 6 able to substantially control the factors that make up 7 the elements being measured. We thought the prime 8 example of this were the measurements around reliability 9 performance, the SAIDI, CAIDI and MAIFI, where many of 10 the factors that are in there are completely outside of 11 the utilities' control, such as lots of supply from a 12 wholesale supplier and the utility would be penalized 13 for poor performance in that area where they absolutely 14 had no choice or control, and so the factors must be in 15 there. 16 The second is that elements that are measured 17 need to be defined in detail to ensure uniform 18 application across all utilities. In the discussion I 19 guess it's how to try to make sure that one size does 20 fit all when you are assigning those types of 21 performance measures. We have tried to offer a number 22 of suggestions. 23 One of the keys that we see in that area is 24 the definition of customer. People like to apply the 25 same types of criteria to customers and I think the 26 Board was talking in a previous conversation about 27 applying a standard formula based on customer count out 28 to utilities. 351 DTE/PROBYN, Presentation 1 Utilities do not measure customers, count 2 customers on the same basis. For example, bulk metered 3 apartment buildings often skew the customer count and so 4 there would have to be an adjustment. 5 Some utilities choose to have a policy to -- 6 they count meters as customers, so they meter a street 7 light and that counts as a customer. So there are wide 8 differences in what constitutes a customer. 9 The third point is that particularly with 10 Sault Ste. Marie there needs to be a recognition for 11 differences between rural and urban as they serve 12 extensive areas of both rural and urban and differences 13 between summer and winter activities. Some of the 14 examples of those is the difficulty with cable locating, 15 providing underground services in the winter often takes 16 considerably longer time than they do in the summertime. 17 The fourth area was recognition for some 18 exceptions that should be excluded from the measures 19 that will skew those measures dramatically, things such 20 as major storms that will skew reliability indices, will 21 skew the customer service indices and a whole variety of 22 indices. So we are looking for an exception that those 23 should be excluded from the measurement system. I think 24 you are looking for ongoing continued good performance, 25 but not a skewed measurement by the utilities. 26 The fifth element was that the PBR measures 27 should not encourage unsafe behaviour by utility staff. 28 We are very concerned with the emergency response 352 DTE/PROBYN, Presentation 1 standard, that it would certainly encourage utility 2 staff to try to meet that target of getting to the site 3 on time and may cause unsafe driving conditions and 4 whatnot. So we think that very cautious looks at any of 5 the measures could be in place to ensure that those 6 types of behaviour aren't encouraged. 7 The sixth, coming back to the last point, we 8 think that all of the measurements should encourage 9 stretch behaviour and encourage innovation by the 10 utility. I think a very good example of that is how the 11 measurement around telephone accessibility, restricting 12 some of the automated technologies that exist for 13 telephone systems. 14 We go into some detail in the submission to 15 talk about some of the differences and how that 16 measurement would actually discourage the utility from 17 using those or something would actually improve customer 18 service. 19 So we want to try to link in and perhaps if 20 there are questions on the detail we can go through the 21 detail on the suggestions that we offer, but I think 22 really based on those six principles what I would like 23 to do is turn it over to Dr. Bolling to provide a 24 greater background and context from which we are trying 25 to make our submission. 26 DR. BOLLING: Thank you. 27 I am particularly honoured to be here today to 28 speak before you. I have reviewed the policy document 353 DTE/PROBYN, Presentation 1 that you are proposing and I must tell you I have looked 2 at many of these and this is very impressive in many 3 ways. Of course, the focus of my discussion today won't 4 deal with the main points on which I am impressed, but 5 rather the few points that I am concerned about. But I 6 will tell you that it is impressive from the point of 7 view that it reaches beyond the transition and it speaks 8 to a long range energy policy environment. 9 Most of the transitions that I am involved 10 with in the States speak only to transition issues and 11 they leave open the long run policy structure. So I 12 think the Board is to be commended on the reach of their 13 ambitions. 14 Now again, I am here today to tell you that I 15 am at odds with several of the material aspects of the 16 Board's report, but I want to make clear that I approach 17 the Board in a true spirit of humility that respects the 18 complexity of the issues that are before you and that 19 also recognizes that there is no single policy fix that 20 is going to attend to all of the needs of all of the 21 stakeholders. 22 I will tell you, however, that my concerns are 23 not idly based. I have been a student and an active 24 participant in these restructurings for somewhat over 20 25 years now. In fact, my Master's thesis which goes back 26 now more years than I'd like to think about. I 27 developed a forward pricing curve for spot market supply 28 curves. 354 DTE/PROBYN, Presentation 1 My doctoral dissertation dealt with the 2 privatization of state-owned enterprises and 3 particularly infrastructure industries. Over the last 4 20 years I have held a variety of management and 5 consulting positions in utilities, here again state 6 utilities, engineering consulting, utility consulting 7 firms and downstream energy service providers. 8 I have testified a number of times before the 9 Federal Energy Regulatory Commission, again in the U.S., 10 the Federal Trade Commission, the Department of Justice. 11 I have testified more times than I would like to think 12 about for both rule making and adjudicative matters 13 before the Michigan Public Service Commission and a 14 variety of other states. 15 Finally, I currently am on the graduate 16 faculties of both Central Michigan University and 17 Oakland University, where I provide graduate instruction 18 in both international business and international 19 political economics course work. 20 So with that let me now turn to substantive 21 matters. I guess one of the striking concerns that I 22 had -- and let me set the context of my comments today. 23 While I am very impressed, as I said earlier, with the 24 policy reach of the Board's position, it strikes me that 25 at touchdown points, at points that really matter to 26 distribution companies I find some inconsistencies with 27 the Board's views. Let me share one of those. 28 I think there is a conspicuous absence of the 355 DTE/PROBYN, Presentation 1 Board's committal to the long-run recovery of potential 2 strandedness for distribution companies. As a matter of 3 fact, I read with great respect, incidentally, 4 Dr. Cannon's work. But one of the criticisms that I 5 would have of that work is that he glossed over the 6 technological revolution that is taking place on the 7 supply side of this industry. 8 If I were to draw -- and I won't take you 9 through all of that because I am a horrible drawer, but 10 if I were to draw your demand curve over the course of 11 the year and look at that bimodal curve in front of us, 12 and then I put the straight line supply curve up above 13 that and the distance between the peaks and the straight 14 line supply curve being the reserve margins, what has to 15 happen with the type of supply mix that we have in North 16 America is that curve has to be pressed downwards. 17 In fact, partly what the restructuring of this 18 business is all about is to drive economic efficiency 19 and supply, kilowatt hour supply. So as that curve gets 20 pushed down -- and we have seen this, by the way, in 21 state after state in the States -- as those reserved 22 margins get pushed down sooner or later we clip the tip 23 of the demand curves. Now, we ask ourselves the 24 economic allocative question: How does that get met? 25 It strikes me recently that one of the 26 interesting provisions of the policy restructuring is 27 the allocative efficiency that comes along with 28 reassigning capital cost to those that want high levels 356 DTE/PROBYN, Presentation 1 of supply certainty. 2 Now, without getting too metaphorical, I sort 3 of liken this to what occurred in the revolution of the 4 transportation business many years ago. Public 5 transportation was the dominant mode of transportation. 6 Well, as that supply curve started pushing 7 down as we drove efficiency in the transportation 8 markets we isolated the tips of the curve and I, for 9 instance, today am going to drive home in a 10 privately-owned vehicle. The supply certainty is an 11 allocative efficiency that came about with the 12 restructuring of that industry and what that means to 13 this industry, at least in my humble judgment, is that 14 we will see supply being downsized and downsized and 15 downsized sooner or later to exotic technologies like 16 fuel cells. 17 But right now we have -- in fact, I was 18 reading an article in The Journal just the other day 19 about the tremendous sale of 8kW to 12kW generators that 20 are Y2K motivated. Well, how long can it be before 21 those are commercial grade and available to all of us? 22 That is the allocative efficiency component 23 that goes into this business, again, in my humble 24 opinion. 25 Now, what that does is it creates the changes 26 that you are making or proposing to make on the supply 27 side of the business, creates an incentive for bypass. 28 It has nothing to do with distribution charges. It has 357 DTE/PROBYN, Presentation 1 to do with consumers taking supply certainty decisions 2 that are not public good but rather economic good in 3 their nature. 4 To my way of thinking, what I would love to 5 see and certainly our client would love to see, is a 6 specific provision in the Board's proposal, in the 7 ultimate policy to be adapted, that recognizes that in 8 the short run these technologies are not there and 9 bypass again. 10 I agree with Dr. Cannon: bypass is not a real 11 threat in the short run. But in the long run it is and 12 it would be nice to see the Commission -- bear in mind 13 the way these system expansions take place is in the 14 spirit of a public good. Right? In fact, it has been 15 cited, and several of the experts have testified before 16 the Board, that distribution companies make these 17 investments in the spirit of public good. Very often 18 times they are uneconomic on their incremental merit. 19 We acknowledge that. 20 Well, it would be awfully nice to see the 21 Board step up to the bar and say, "Look, no matter what 22 happens in the long run, these distribution investments 23 that you make in the spirit of public committedness 24 won't be stranded." 25 So, again, to my way of thinking, that is a 26 conspicuous omission. We hint around at all of that. 27 In fact, Dr. Cannon speaks to the -- in my mind, into a 28 glossary of a way that the Board will certainly belly-up 358 DTE/PROBYN, Presentation 1 to the bar given any specific instance of strandedness. 2 Well, as an investor, I would like to see something more 3 positive and I encourage the Board to that end. 4 The second element that I find a little bit 5 troubling -- and I do understand that the particular 6 area that we are discussing today, the distribution 7 system, it would be wrong-minded to think of it, at 8 least at this stage, entirely as an economic good. It 9 is more properly characterized as a public good and what 10 we are dealing with -- I think what the Board is dealing 11 with, at least through my eyes, is lighthanded 12 regulation, the possibility of lighthanded regulation of 13 that public good evolving over the long run to an 14 economic good. 15 One of the concerns I have, however, is with 16 the productivity factor ROE choice matrix that was 17 proposed by the OEM. I guess to my way of thinking it 18 is intuitively obvious that the outputs, the efficiency 19 outputs associated with those inputs are not linearly 20 related as the matrix suggests. There has to be, and we 21 know this is true -- whether or not we are in the 22 relevant domain we are not completely sure, but we know 23 it is true that the efficiencies that result from those 24 input investments sooner or later have to diminish in 25 their return. 26 What I would encourage the Board to do is to 27 factor that into the matrix. This has the effect, at 28 least in my opinion, of punishing utilities that are on 359 DTE/PROBYN, Presentation 1 the frontier of efficiency. What we want to do is 2 recognize -- at least I think what you would like to do 3 is to recognize that they have to put more input 4 investment to get an equal output return, output 5 efficiency return. So my suggestion would be to design 6 the matrix in that way. 7 There are so many proposals, and actually this 8 one in some ways resembles that -- well, we are not 9 exactly sure, at least I am not as I step back and say: 10 What is it that the Board is trying to achieve with 11 respect to the rewards for entrepreneurs and the 12 safeguards for consumers? What is it that we are trying 13 to achieve? 14 It strikes me, at least at first blush, that 15 the Board's concern is -- although, I don't think their 16 policy focus is there, I think at these touchdown points 17 the concern is more focused on bridling 18 entrepreneurial/monopoly rents than it is on encouraging 19 the market. I would suggest that you have an awful long 20 time to reign in monopoly rents. 21 What I would encourage the Board to do is to 22 think about the extent to which you inappropriately may 23 bridle entrepreneurial rents. Again, I think this 24 choice matrix may be such an illustration. 25 The next point I would like to raise deals 26 with, in the best case, regulatory lag associated with 27 investment recovery. 28 I must tell you, the earlier speaker lost me a 360 DTE/PROBYN, Presentation 1 bit. He is clearly more of a student on the accounting 2 mechanisms than I am. But I must tell you, I view this 3 issue very differently than he does. I am less 4 concerned about some cross and sunk benefits because I 5 think this market is going to commercialize and I think 6 that stuff gets largely wrung out in that 7 commercialization process. That is my view. That, 8 incidentally, is the case with most privatizations I 9 have found. 10 Now, the conspicuous problem that I have, and 11 again it may be my lack of understanding of this, deals 12 with the growth on the system. When you envision a 13 distribution system, at least the way I do, there are 14 sort of two components: the backbone to the system is a 15 public good, while I think of the service drop as an 16 economic good -- clearly, only one benefactor. 17 I'm not too troubled with the general 18 structure of how you intend to recover those capital 19 investments except that I can't find a growth factor 20 here. I can't find anything recognizing the capital 21 that goes into new growth post the transition. 22 It seems to me that the PBR formula ought to 23 recognize a kVA growth factor. Now, I'm not here to 24 propose exactly how that should be laid out, however, we 25 could put some proposals. I have seen some very clever 26 ones, whether it is a head count and a meter count or a 27 tVA, I'm not exactly sure. But it seems to me that that 28 is conspicuously absent. 361 DTE/PROBYN, Presentation 1 The next point I would love to touch on is 2 with the productivity factor development and I will tell 3 you that here I have very deep concerns that the 4 consultant who assembled that, at least in my opinion, 5 confused some issues. 6 Now, you will remember -- and I am going to 7 focus in on the three-factor approach, the labour, the 8 capital and the materials. If you will recall how those 9 were arrived, and let's focus on the capital first, it 10 is deployed capital, right? There is an estimate in the 11 beginning and then in the long run some de facto on 12 deployed capital, and then the returns are net capital. 13 Now, think about that for a little bit in 14 terms of the history of the data of the statistic that 15 was put together. It confuses price increases with 16 efficiency increases. We are not sure, when we look at 17 that curve, are we looking at the capital increases 18 attributable to the goods themselves and whatever 19 carrying charges might have escalated along with those 20 or are we looking at the efficiency with which the 21 capital was deployed over that roughly 10-year period, 22 and I will suggest to you no one knows. 23 I think the same thing is true on labour. I'm 24 not exactly sure of the curve that I'm looking at. Oh, 25 by the way, there is a question in my mind as to whether 26 or not the line wages that we used as a proxy for 27 average wage, I'm not sure -- I have seen no evidence to 28 suggest that that is a good proxy. But what is more 362 DTE/PROBYN, Presentation 1 than that, once again we confuse the efficiency of the 2 deployment of labour because we take into account the 3 number of people with the escalation on the labour. The 4 same thing could be true in the material sense. 5 I would tell you, as a scientist I looked at 6 the CPI curve that was presented by Hagler Bailly. I 7 could cite that section for you if you like. But, 8 actually, my recollection is there is only one time 9 series in there that compares a CPI curve and the 10 three-factor curve and the four-factor curve. Those 11 curves look so wildly dissimilar, the three-factor curve 12 and the CPI curve, that I was stunned that nobody took 13 up the question of why. 14 How can we recognize the possibility that that 15 three-factor curve is so wildly different than the CPI? 16 Conceptually, how do we resolve that? 17 I would tell you that I can't. 18 I think what Hagler and Bailly did was sort of 19 overlook that and took the two end points of the curve 20 and kind of smoothed it out. What I would suggest to 21 you that I don't think it is right. 22 My suspicion is that it is wrong and that it 23 is biased by downturns in the North American equipment 24 industry and probably heavily biased by the 25 restructuring anxiety that was created among 26 distribution firms which affected their capital and 27 labour deployment issues. 28 But even if it were right, it doesn't separate 363 DTE/PROBYN, Presentation 1 out the efficiencies from the escalation on those three 2 components. I think there are better proxies for that. 3 I am not altogether familiar with the Canadian 4 statistics, but if they are like the U.S. -- and I 5 suspect that there are similarities -- one could go 6 back to a SIC code kind of identification of that 7 equipment and get probably a better proxy for those 8 escalations. 9 About 50 per cent of the curve, incidentally, 10 is driven, as you perhaps know, by capital investments. 11 Again, I suspect that that curve could be 12 assembled in a much more reliable way and in a way that 13 doesn't start out penalizing distribution companies. 14 The other component there -- and this will 15 show up in another place too -- which I have redubbed a 16 PPI, or a producer price index, is a comparative 17 efficiency component. 18 It strikes me through various citations in the 19 position paper that the Board is trying to think about 20 efficiencies in two ways. It is trying to think about 21 firm efficiency as it changes over time, and it is 22 trying to encourage that. But it is also trying to 23 encourage relative efficiency. 24 I don't think those have been accomplished in 25 the formulae that have been laid out in the PPI. What I 26 think part of the issue is, is we need something in 27 there on comparative efficiency. 28 By that, what I mean is what we really want to 364 DTE/PROBYN, Presentation 1 do, it seems to me, is reward a firm or create 2 incentives for efficiencies within the firm itself. 3 By the way, the measure of this, let's just 4 broadly think about today to be a total cost per KW. 5 That may not be the right statistic to use ultimately 6 but just to sort of set the thinking. 7 Then what we want to do is we want to place 8 that, a given utility, within the framework, within the 9 industry of Ontario utilities, to measure their 10 comparative efficiency progress. 11 There are systems that others have deployed. 12 By the way, we will be submitting some text on 13 these various issues, and we will provide these exhibits 14 for the Board's review and consideration. 15 It seems to me that that is a missing 16 component, this absolute firm efficiency over time and 17 then the comparative firm efficiency. Those are the 18 behaviours, it seems to me, that you are trying to 19 motivate. But it is absent in the formulae. 20 One of the other concerns that I would suggest 21 -- well, I don't have to suggest; I know I have this, 22 but I would encourage you to consider -- is that -- 23 And by the way, I a going to mention just one 24 of these, but there are several instances where I find 25 this to be the case. 26 Where there is long-run uncertainty with 27 respect to market structure or the evolution of market, 28 that risk gets pushed to the municipal utility. 365 DTE/PROBYN, Presentation 1 I will give you a classic case in point. 2 Is it the Board's intention -- and I think 3 the answer to this is that probably we don't know now. 4 But the question is: Is it the Board's intention to 5 open up the downstream distribution activities to new 6 entrants: metering, billing reconciliations, and that 7 sort of stuff; meter reading; answering telephones; all 8 that -- not all, but a good deal of that customer 9 interface stuff. 10 If it is the Board's intention to do that, it 11 seems to me that that should be laid out pretty clearly, 12 because otherwise how can a distribution company now 13 decide to take a decision to invest in those 14 technologies? 15 There are voice response technologies that I 16 am personally acquainted with which are reported to be, 17 as I run through their test periods, quite efficient. 18 How could one decide to implement that now? 19 To my way of thinking, I would certainly 20 advise my client: Don't do anything until you know what 21 the market structure looks like. If they are going to 22 open it up to competition, that means -- just opening it 23 up to competition, the issues that cloud that are: What 24 will be the LDCs' allowed role as that market opens up? 25 It's not just a question of it going to 26 market. We are not trying to hide inefficiencies. We 27 are curious and anxious about what the structure will be 28 and what the permissable role of the municipal utility 366 DTE/PROBYN, Presentation 1 will be in those structures. 2 The last point I am going to speak to is the 3 issue of pricing flexibility. 4 As near as I could discern from the earlier 5 speaker, one of the issues, although I would get at it 6 very differently than he, I probably agree with; and it 7 was the issue of how you go about setting rates to begin 8 with. 9 As I understand the proposal that you are 10 contemplating now, we would systematically algebraically 11 pull out supply cost and then presume what was left was 12 delivery cost. 13 I would favour a bottom-up approach. I think 14 that top-down approach raises a whole host of questions 15 about whether or not the existing rates properly 16 reflected cost components across supply and demand, and 17 actually demand components particularly across the 18 spectrum of customers that are being served. 19 My suspicion is that they probably don't, 20 because there wasn't an incentive in place to properly 21 align those economic costs, at least in most of the 22 policy environments which I am familiar with. And it is 23 not uncommon that they are all screwed up. 24 So I would agree with the previous speaker, 25 for very different motivations. I would think a 26 bottom-up approach is a much handier way to come to 27 terms with what the starting point rates should be. 28 Those have certainly hit the highlight of my 367 DTE/PROBYN, Presentation 1 concerns. We will have some other lesser issues in our 2 final submittal to the Board. But I would be happy to 3 answer any questions. 4 I realize that I went pretty quickly. 5 THE PRESIDING MEMBER: Thank you. 6 Is there any more or is that your 7 presentation? 8 MR. ALLEN: Yes, we have a couple of summing 9 comments. 10 THE PRESIDING MEMBER: I am concerned about 11 the fact that Mr. Healey and Mr. Babaie have a flight. 12 I don't know whether there are any comments that they 13 wanted to make. Perhaps they could make them before 14 they have to leave. 15 MR. BABAIE: No. 16 MR. ALLEN: No, they don't. 17 THE PRESIDING MEMBER: Mr. Vlahos has some 18 questions. 19 MEMBER VLAHOS: Mr. Bolling, on your last 20 comment about the bottom-up versus top-down, by 21 bottom-up, is this cost of service? Is this what you 22 mean? 23 MR. BOLLING: Yes, it is. 24 MEMBER VLAHOS: I guess one of the 25 considerations here is that the utilities have to have 26 new rates in place quickly. Given the number of them, 27 over 250, and the very small size for most of them, such 28 an exercise would take a long time. In the meantime, 368 DTE/PROBYN 1 something has to be done by this Board, with rates going 2 forward. 3 Do you have any advice? Were you aware of 4 those constraints? 5 MR. BOLLING: I was aware. And my comment to 6 that would be -- I am not troubled using what the Board 7 has proposed as a guideline, but I think it should give 8 way to a more detailed bottom-up approach if the 9 municipal would submit that either in the short run or 10 in the longer run. 11 MEMBER VLAHOS: Okay. So it would be 12 optional, if you like. If the utility itself would like 13 to come forward with a cost of service, the Board should 14 encourage that. Is that what I hear? 15 MR. BOLLING: That is my recommendation. 16 Doctor, did you have a comment? You look like 17 you were going to amend that question. 18 MEMBER ZERKER: No, I thought that was pretty 19 clear. I did want to ask you about your first point. 20 I take it that you mean that the Board's plan 21 ought to have some form of commitment to assure 22 investors in current technology that they won't be 23 stranded by the forthcoming more revolutionary 24 technologies. Is that right? 25 MR. BOLLING: That is correct, Doctor. 26 MEMBER ZERKER: How would you suggest that we 27 do that? 28 MR. BOLLING: Well, I think you have hinted to 369 DTE/PROBYN 1 it now in the document, but I think the statement should 2 be pretty clear on its face. To the extent that you 3 serve customers under an obligation, you will recover 4 that capital investment. I think the Board should stand 5 behind that. 6 MEMBER ZERKER: The capital investment, 7 regardless of whether or not it physically becomes 8 stranded, will not be stranded financially. 9 MR. BOLLING: That is correct. 10 MEMBER ZERKER: I see. 11 MR. BOLLING: Doctor, let me, if I may, add to 12 that. 13 It seems to me that that is right-minded, 14 because if you and I were in business and we sensed the 15 long run technology threat, the way we would deal with 16 that is we would either not make the investment or we 17 would depreciate it appropriately. 18 Now, here we have a case where the 19 depreciation rates are being set on physical lives. 20 They have virtually nothing to do with technology risk, 21 technology turnover. So it seems to me that in the 22 light of those possibilities that the staff ought to be 23 affirmative on that issue. 24 MEMBER ZERKER: My concern is that we are 25 dealing with an unknown. I mean, when there is a known 26 and you know that there is this technology there that 27 your competitor has or there is a stream of technologies 28 that are moving into a competing position. But as you 370 DTE/PROBYN 1 know and I know, technologies are unpredictable in the 2 world we live in and businesses that have a return on 3 capital, unlike the history of this company, have to 4 take their chances. 5 MR. BOLLING: Let me insert, if I may. 6 They have no chance to take, they are 7 obligated to serve. They have no opportunity to say, 8 'We are not going to hook you up because we can see 9 micro-technologies coming in in the next two or three 10 years and we think our investment is going to be 11 stranded". They do not have that opportunity. 12 I share with you that there is this unknown, 13 but I think that is the given. The issue is, who takes 14 the risk of the unknown, in my humble view. 15 What I am suggesting is that given the 16 critical difference of this business, at least in the 17 short run, is that it is more public good, this delivery 18 system, and the obligation -- I think the governance 19 obligation is to ensure investors because they are 20 obligated to make that hook-up they are going to get 21 that money back. 22 --- Pause 23 THE PRESIDING MEMBER: Mr. Vlahos? 24 --- Pause 25 MEMBER VLAHOS: Dr. Bowling, just back to me. 26 MR. BOLLING: Yes. 27 MEMBER VLAHOS: I just want to discuss with 28 you the absence of the so-called growth factor that you 371 DTE/PROBYN 1 brought up and I just wonder whether that is connected. 2 Here I am seeking some advice and input from you where 3 this may be connected to the way capital is reflected in 4 the IPI factor which is part of the PBR formula. 5 Have you had a chance to turn your mind to it? 6 Based on your reading, do you think there is a 7 connection there? 8 MR. BOLLING: No, I don't. I think the IPI is 9 designed -- although again I take exception to the 10 algebra -- it is designed to pick up producer price 11 increases for capital equipment. It is not designed to 12 pick up kVA additions. That is my read of that. 13 Go ahead, I'm sorry. 14 MEMBER VLAHOS: I'm sorry. 15 You mentioned that you have considerable 16 experience about other programs, PBR programs in other 17 jurisdictions. You called them, I'm sorry, kVA? 18 MR. BOLLING: Yes. 19 MEMBER VLAHOS: Let's call it growth factor, 20 the growth factor. 21 MR. BOLLING: That's correct. Yes, growth 22 factor is good. 23 MEMBER VLAHOS: So the growth factor is always 24 part of a comprehensive PBR? 25 MR. BOLLING: I have seen three or four of 26 these and I have not seen one absent that. 27 Again, I would be happy to send you what I 28 have, which is probably fairly extensive. 372 DTE/PROBYN 1 MEMBER VLAHOS: I'm sure we have plenty on the 2 record. Thank you for the offer, but we do have -- 3 MR. BOLLING: I understand. I'm sorry. 4 MEMBER VLAHOS: No, I appreciate the offer, 5 but we did go through a proceeding some time ago, a 6 limited PBR but nevertheless we have quite a bit of 7 literature -- 8 MR. BOLLING: And on that issue on the growth 9 factor? 10 MEMBER VLAHOS: -- and we can consult with 11 those. 12 MR. BOLLING: I was a little confused. Let me 13 do tell you, if I may, I was a little confused because 14 your capital contribution is different than what I am 15 accustomed to seeing. Incidentally, I think far 16 superior than what I am accustomed to seeing. 17 It is the first time that I have seen the 18 distinction in a distribution plant between incremental 19 economic goods and sunk public goods. I think that is 20 an important and critical distinction. It absolutely, 21 in my judgment, sends the right price signal for 22 delivery services. 23 But I got a little confused because it was not 24 clear to me whether or not the thinking was or the 25 history has been that all system costs, all system 26 investment costs, are borne through the contribution 27 component or not. 28 Now, they should not be. What happens is, if 373 DTE/PROBYN 1 I were to hook up as a new customer I may cause 2 reprotection of the circuit, I may cause reconductoring 3 of the circuit, may cause a new transformer to go in, 4 which have little if anything to do with my incremental 5 addition. They are really part of the public good of 6 the system backbone. 7 I see no way -- in fact, I think what will 8 happen, if I am interpreting the algebra properly, is it 9 will systematically lead to the deterioration of 10 distribution system backbone. Because there is no way 11 to compensated for those investments the rational 12 manager is going to have to skin you up on those. Here 13 again, if I understand that properly. 14 MEMBER VLAHOS: Okay. Well, let me just 15 follow that up. 16 What is your understanding of what this 17 component called "capital", cost of capital and changes 18 to the cost of capital -- what is the purpose of being 19 treated as a third component of the IPI? 20 Can you first explain to us as to how it is 21 constructed and what is its objective, based on your 22 understanding? 23 MR. BOLLING: Sure. 24 May I first draw the distinction, what I have 25 been talking about in terms of kVA growth is different 26 than your IPI, and the IPI doesn't deal with it 27 whatsoever. 28 Whether those capital additions, backbone 374 DTE/PROBYN 1 capital additions are dealt with at all seems to be not, 2 but I want to start by drawing that distinction and then 3 answer your question. 4 MEMBER VLAHOS: Right. I understand the 5 distinction, Doctor, I just want to make sure that when 6 we discuss that that, you know, you think there is no 7 link but there may be a link -- or somewhere there may 8 be a link, I don't know. 9 MR. BOLLING: That's conceivable for sure. 10 The IPI -- and you are asking about the 11 capital component specifically -- is designed to do two 12 things, as I understand it, to pick up inflationary cost 13 on delivery system componentry, transformers, wires and 14 whatnot, inflate over time -- well, normally inflate 15 over time and it is designed to pick that up. 16 MEMBER VLAHOS: Could I just keep stopping you 17 so that -- 18 MR. BOLLING: Of course, yes. 19 MEMBER VLAHOS: -- we can have a discussion? 20 So the assumption here is that whatever is 21 affecting the rates currently or going in the rates -- 22 MR. BOLLING: Okay. 23 MEMBER VLAHOS: -- then that is reflected in 24 the rates. So lets call it an investment expenditure of 25 on average $10 million for example. 26 MR. BOLLING: Yes. 27 MEMBER VLAHOS: Then moving forward, then 28 there is a recognition that the capital investment may 375 DTE/PROBYN 1 be about on average the same, but we have to allow for 2 some inflation on the price of capital -- capital goods 3 that is. 4 MR. BOLLING: Yes. 5 MEMBER VLAHOS: When I hear the word "capital" 6 I always try to think of the shareholder capital and 7 here we are talking about something different. 8 MR. BOLLING: Yes. 9 MEMBER VLAHOS: Okay. 10 Okay, go ahead. That is the first component. 11 That is the first thing he is trying to capture. 12 MR. BOLLING: Yes. 13 MEMBER VLAHOS: The inflation on the capital 14 expenditures moving forward and the assumption is that 15 those capital expenditures will be about the same as 16 they have been historically. 17 MR. BOLLING: That's correct. In fact, that 18 is the essential thing that I think. They have 19 something else in there which I earlier argued should 20 not be there, and that is the quantity of capital that 21 is deployed, which is an efficiency issue, it has 22 nothing to do with inflation. 23 MEMBER VLAHOS: Okay. That's what I want to 24 understand, sir. 25 So there is that second point based on the 26 formula as per the Board staff's proposal? 27 MR. BOLLING: That's my understanding. That 28 is my interpretation of that, yes. 376 DTE/PROBYN 1 MEMBER VLAHOS: Okay. Tell me what your 2 understanding of that is, exactly what that is. 3 MR. BOLLING: It includes both the escalation 4 and the quantity of capital that is deployed. 5 Now, why that is significant, certainly in the 6 starting PBR and actually formalistically important from 7 that point forward, is it takes us away now from the 8 escalation that you just a moment ago described on 9 equipment and now we are dealing with a factor that 10 deals with how much equipment we have deployed, which is 11 an efficiency issue. 12 MEMBER VLAHOS: Okay, sir. How is the 13 quantity derived? Is it an index? Is it absolute 14 amounts? What is its source? What is your 15 understanding? 16 MR. BOLLING: You know, I would have to go 17 back and study that a little bit more carefully. 18 MEMBER VLAHOS: All right. That's fine. 19 MR. BOLLING: I can't recite that to you now. 20 MEMBER VLAHOS: Okay. So, continue. 21 So there is a concern, in your view, about 22 once you have -- you have looked at the first 23 component, which is inflation costs over time. Then why 24 do you bother with the second step? 25 MR. BOLLING: Well, not just that you 26 shouldn't bother with it; it's inappropriate to put it 27 there. 28 Basically, what the PBR, if you step back and 377 DTE/PROBYN 1 look at the over-arching algebra, here's what it's 2 trying to do, and you said it a moment ago, it's trying 3 to start with a rate -- and let's assume that that's a 4 good rate, to begin with -- it's trying to increase 5 that rate by unavoidable inflation; it's trying to 6 reduce that rate by efficiency gains that the Board 7 anticipates and, then, lastly, it's trying to throw in 8 an adder for exogenous costs, unavoidable exogenous 9 costs. That's what it's trying to do. 10 Now, what we have done here is we have 11 confused two factors. We will start with the 12 presumption that we have a good cost base rate going in. 13 Now what we have done is inflated it up by capital, 14 labour and material, but then we deflated that deflator 15 by taking in the efficiency of the deployment of those 16 elements of cost, and now we add, on top of that, an 17 efficiency improvement factor. And then, of course, we 18 add back in the Z-factor. 19 So we doubled up on the efficiency is the 20 point. 21 Whenever you take into account the quantities 22 on these resources and put that into the escalation 23 formula, it's inappropriately double-dipping, at least 24 as I interpret that algebra. 25 MEMBER VLAHOS: Thank you. 26 And absolutely no link to the growth factor? 27 MR. BOLLING: No, but growth factor, near as I 28 can tell, isn't there at all. Other than the capital 378 DTE/PROBYN 1 contribution, there is nothing for system growth factor. 2 MEMBER VLAHOS: Thank you. 3 THE PRESIDING MEMBER: Could I understand 4 system growth factor. This is dealing with a price as 5 opposed to a revenue escalator. So the kVA growth 6 factor is an increase in the costs or prices related to 7 the type of installation. Is that what it's supposed to 8 reflect? 9 MR. BOLLING: No; I'm sorry, Mr. Chairman. My 10 interpretation of the kVA growth factor is for system 11 backbone costs which cannot be properly economically 12 allocated to incremental load. If I build a new house 13 over here -- and I might; it's so beautiful here -- 14 I'm going to pay for the -- presumably, or 15 conceptually, under the model that we have -- I'm going 16 to pay for the service drop. That cost is going to be 17 specifically allocated to me. But if the transformer 18 has to be upgraded to pick up my costs, I don't pay for 19 that. Nor does anybody else pay for that. And by the 20 way, it would be wrong for me to pay for that. 21 Only to the extent that that new transformer 22 was sized only to meet my incremental load would it be 23 appropriate to charge me incrementally for that. But 24 that, normally, isn't the case. Normally, when you put 25 a transformer in, you are recognizing growth in the 26 area. And so, that incremental transformer cost should 27 be borne as a public-good cost to the whole system. 28 Now, when I go back to the algebra, I find no 379 DTE/PROBYN 1 provision to pick up those backbone or public-good costs 2 for distribution system expansion. 3 But, by the way, one of the characteristic 4 costs that you see as you evolve from rural- to 5 suburban- to urban-type growth is your reconductor 6 systems. Who would pay for that, under the model that 7 you have? It strikes me that the municipal utility 8 would. There is no customer that picks that cost up, as 9 near as I can determine. 10 THE PRESIDING MEMBER: But wouldn't that cost 11 be normal in any system, that you have to upgrade the 12 overall system or you have to replace the overall system 13 as it wears out? 14 MR. BOLLING: That's depreciation -- forgive 15 me, Mr. Chairman. Go ahead with the question. I'm 16 sorry. 17 THE PRESIDING MEMBER: But the depreciation 18 provides cash flow for doing that? 19 MR. BOLLING: No. Depreciation provides cash 20 for like-for-like replacement. 21 THE PRESIDING MEMBER: Okay. 22 MR. BOLLING: It does not provide upgrade 23 backbone improve cash. 24 MR. ALLEN: If I may offer -- the concept is 25 that you think of two systems: one system that has 26 absolutely no load growth, that will have to be renewed 27 and rebuilt, requires a certain set of revenues that the 28 changes in the IPI would certainly adequately reflect. 380 DTE/PROBYN 1 Now, you have another municipality, for example, that 2 could be growing in extremely high rate and you are not 3 able to recover the system costs associated with that 4 growth portion of it; you are just simply recovering 5 historic costs. 6 MR. BOLLING: That's well said -- at least 7 well said for my -- 8 MEMBER VLAHOS: Right. Okay. First of all, 9 what's kVA? Could you just give us -- 10 MR. BOLLING: Kilovolt amp. 11 MEMBER VLAHOS: Sorry? 12 MR. BOLLING: Kilovolt amp. 13 MEMBER VLAHOS: All right. 14 MR. BOLLING: It's a watt. It's a measurement 15 of the demand that a customer puts on the system. 16 MEMBER VLAHOS: Okay. And I guess a growth 17 factor, I mean, it could be based on other things; it 18 could be on customers; it could be on some other index. 19 MR. BOLLING: I think it probably could, yes. 20 MEMBER VLAHOS: Okay. Is it, then, implicit 21 -- in the absence of a growth factor, is the implicit 22 assumption here, in the form of a bulletin by Board 23 staff, that a given system or the average system would 24 not need any more capital that it's already recognized 25 in its current rates and the only thing we have to take 26 care of just inflation on that capital? 27 MR. BOLLING: That is my interpretation of the 28 staff's proposal. 381 DTE/PROBYN 1 MEMBER VLAHOS: Okay. So -- 2 MR. BOLLING: But may I just annex that with 3 just one brief comment. But for capital contributions. 4 Incremental system costs that can be linked to a 5 particular incremental load. 6 MEMBER VLAHOS: Okay. So -- 7 MR. BOLLING: -- allowance for the 8 depreciation of the system that doesn't change and the 9 incremental investment attributable to a customer. 10 MEMBER VLAHOS: Okay. 11 MR. BOLLING: What's missing is the 12 incremental investment to keep the system strong. 13 MEMBER VLAHOS: Okay. So if we make an 14 assumption about a system that is mature, then the 15 absence of a growth factor would not be of a great 16 concern, would it? 17 MR. BOLLING: It would not be to me, that is 18 correct. 19 MEMBER VLAHOS: What is your knowledge about 20 the Ontario system, Doctor? 21 MR. BOLLING: I would tell you generally -- 22 we, by the way, have studied the Ontario system, as I 23 have studied the system of other countries for a variety 24 of policy-related reasons, and what I will tell you is 25 that, characteristically, what happens -- I think this 26 is the case here, as well -- is that urban systems tend 27 to be more or less mature; rural systems tend to undergo 28 change very slowly; and suburban systems change a lot. 382 DTE/PROBYN 1 Now, I would invite staff to throw a word in 2 on that, but that's pretty characteristic and, I think, 3 reflects what our findings were on this system and the 4 various Ontario systems sometime ago. 5 MEMBER VLAHOS: Just take the other extreme. 6 If we have a very mature system, such that there is 7 absolutely nothing spent other than just maintenance, 8 where you are going to have a very large depreciation 9 -- I'm sorry -- if you start with a large depreciation 10 expense but you have very little depreciation expense at 11 the end, then should there be another negative factor in 12 that formula, as opposed to a positive factor? 13 MR. BOLLING: No; the way -- Dr. Cannon deals 14 with this quite well, I think, in his treatise on the 15 various financial aspects of the evolution that you are 16 undertaking. But to me, the right-minded way -- and 17 certainly the way Dr. Cannon presents it I believe to be 18 right-minded -- is that you now think about a perpetual 19 asset. That's the essence of this new accounting on the 20 system. And so, to think about exhausting the life on 21 the system doesn't work financially; it's all -- and 22 probably isn't right-minded conceptually. 23 MEMBER VLAHOS: I guess this question is to 24 all the gentlemen on the panel. 25 When you brought this concern up at the 26 technical conference, when Board staff and other people 27 were present, what was your understanding as to what the 28 assumption was that there was now a growth factor in the 383 DTE/PROBYN 1 formula? What has been the response? 2 MR. ALLEN: I think there's a recognized 3 concern, and I think it really was from the point of 4 view of the utility that if they are a mature utility 5 that doesn't have much growth, then it isn't a very big 6 concern. And I think it has been phrased correctly that 7 it's the suburban utilities -- particularly if you look 8 at the 905-type utilities -- are the ones that are 9 experiencing the growth and are going to have the most 10 concern over this. 11 There wasn't a great discussion, in-depth 12 discussion, on it, but there was very positive 13 recognition from a number of the utilities to say, "Yes, 14 that makes a lot of sense". 15 MEMBER VLAHOS: Okay. Was there a specific 16 response by Board staff's consultants during the 17 technical conference? Is it on the record that I can go 18 to and do some reading? 19 MR. ALLEN: There wasn't anything, I guess -- 20 I can't recall if there was a very specific comment on 21 it. It was certainly -- 22 MR. BABAIE: There was certainly questions and 23 answers. Just simply that. It wasn't kind of agreed 24 points of view on number of issues. Mostly, we were 25 here, presented a point and submission, and there were 26 set of questions for clarification. 27 MEMBER VLAHOS: So you didn't get any 28 indication from Board staff consultants as to the 384 DTE/PROBYN 1 reasons, their reasons why they saw appropriate note in 2 their growth factor? 3 MR. ALLEN: No. 4 MR. BABAIE: I don't recall. 5 MEMBER VLAHOS: All right. Thank you. 6 Just one last question -- 7 THE PRESIDING MEMBER: Just before you leave 8 that. 9 If you were to include a kVA growth factor, 10 how would you determine it? 11 MR. BOLLING: Again, I would send you astray 12 if I get into that detail today. I would be talking 13 beyond my recollection. 14 I would be -- and I will submit more specific 15 concrete ways to think about that. 16 THE PRESIDING MEMBER: Thank you. 17 MR. ALLEN: As a suggestion, what has been 18 included from the old Development Charges Act was a 19 piece of the Development Charges Act that really allowed 20 utilities to recover a certain percentage, certain 21 revenues that you could collect from development 22 charges, and it was all really based on that type of 23 incremental system growth and, like, a part of your 24 development charges were things that were for, as 25 Dr. Bolling calls it, for the public-good portion of the 26 system, and so, that might be a way of thinking about 27 some of those. 28 And, again, the utilities that adopted 385 DTE/PROBYN 1 development charges to recover those types of ones were 2 ones that were experiencing very high growth. Utilities 3 that weren't experiencing high growth, there was no 4 benefit and, thus, they would not collect very much and 5 so, they didn't proceed with that type of bylaw. 6 MR. BOLLING: Let me do mention, too, as I 7 think more about it, at least in the States -- and I 8 suspect it's true here because the uniform system of 9 accounts are closely parallel -- that there's a 10 distinguishing account for system strengthening versus 11 incremental load and, in the long run, you know, you 12 would actually have those investment dollars to look at. 13 And if one decided to audit it back down, you would have 14 the work orders on which the investments were made. 15 THE PRESIDING MEMBER: If I can just -- 16 carrying back to the question there are rates that 17 exist, the rates that exist, there are two costs, in 18 effect, you are saying, of attaching new customers: the 19 cost to go to the person, or a company premises; and 20 then there's the other costs, which is what's required 21 in strengthening the system to accommodate it. But the 22 rates that currently exist, that existing customers pay, 23 include some component towards maintaining the system. 24 Now, the new customer comes on. Doesn't the 25 rate he pays also include some component towards 26 maintaining the system, as opposed to just the rate to 27 cover off his attachment costs? 28 MR. BOLLING: No. And if I can, let me 386 DTE/PROBYN 1 exemplify the difference. 2 What if suppose that a new customer -- that 3 nth new customer requires that the backbone of the 4 system be reconductored, from a six copper to a 5 three-ought aluminium. What we have built into the 6 rates is the specific service drop for that new 7 customer, and any other incremental investments required 8 and used primarily exclusively by that new load and we 9 have all the depreciation for the old system's cost but 10 we do not have the cost of the new three-ought copper 11 -- I'm sorry -- three-ought aluminium, in the example, 12 less the salvage value of the copper, that isn't any 13 place. 14 MEMBER VLAHOS: So you had that. If there was 15 another customer that was attached the prior period and 16 that was recognized in rates, the assumption is that the 17 customer that's been attached will have a similar 18 expenditure pattern as the previous customer, so certain 19 rates would capture that. 20 MR. BOLLING: It only captures the conductor 21 that was replaced. It doesn't capture the new cost of 22 the incremental cost of the new backbone conductor. 23 What we are doing, you know, is -- I don't 24 know how familiar you are with distribution systems, but 25 let's just assume that we have a radio system where we 26 have this backbone and then stretching off of this, we 27 drop down to pick up loads. Sooner or later, we have to 28 reconductor that backbone of the system, that central 387 DTE/PROBYN 1 core of the system. Sooner or later, the loads generate 2 heat on those old conductors that they can't take. All 3 the customers that are on that system, including the new 4 customer, pay a system backbone cost that's for the old 5 conductor. 6 When we reconductor that, who pays for that? 7 Nobody. 8 MEMBER VLAHOS: Right. 9 MR. BOLLING: The depreciation rate pays for 10 the old conductor, not the new one. 11 THE PRESIDING MEMBER: The new customer is not 12 -- is paying for the existing system, but that's 13 already covered by the rates from the existing 14 customers. So that part that he's paying the existing 15 system surely must go towards something other than 16 paying it or else we are just going to have completely 17 declining rates. 18 MR. BOLLING: Let's take an example, again -- 19 maybe these examples don't work. I always tell my wife 20 that. She gives me so many metaphors I get swimming; I 21 could write a novel but I never really understand the 22 issue. But let me try to use her tactic on you. 23 What if suppose that the conductor, the copper 24 conductor that we are replacing has a net book cost of 25 $1,000 and a salvage cost of $200. 26 Now, along comes this new conductor. We are 27 reconfiguring the backbone of the system. We are going 28 to take down this old conductor and put a new one up -- 388 DTE/PROBYN 1 actually, three new ones. They found three old ones, 2 put three new ones up. But the new is $2,000. 3 Now, let's examine who pays for what under 4 that scenario. The existing rates pay, if rates are 5 current they pay for the net book value on the old 6 conductors, or they have $800 of depreciation to go. 7 Right? 8 But now we have just added, what did I say, 9 $2,000? We have just added another $1,200 of 10 incremental expense. If I collect all the depreciation 11 out of the existing rates I won't pick up that $1,200. 12 The only way to pick it up that I am aware of is to 13 reconfigure the rate to recognize that incremental 14 investment, otherwise it won't get paid. 15 MEMBER ZERKER: Your example was a proportion 16 of that goes into the K-factor in the IPI? 17 MR. BOLLING: Which was the K-factor again? I 18 have forgotten. 19 MEMBER ZERKER: The per capital, I am talking 20 about three -- 21 MR. BOLLING: None of it goes in there. 22 MEMBER ZERKER: None of it goes into the IPI? 23 MR. BOLLING: No. It's not designed to do 24 that. It is designed to pick up -- if you take the 25 imperfection or what I believe to be the imperfection of 26 the system, that factor in general is designed to pick 27 up escalation on capital components on the delivery 28 system, just like the labour component it's designed to 389 DTE/PROBYN 1 pick up escalation labour rates and just like the 2 materials component is designed to pick up escalation 3 and materials. 4 MEMBER VLAHOS: I ask you to think of exactly 5 what you described to us and move yourself to the 6 previous period, a year ago. 7 MR. BOLLING: A year ago. 8 MEMBER VLAHOS: A year ago, that when rates 9 were set and there had been a mix of all those. All 10 that mix, the net effect is reflected in the rates that 11 are being approved. 12 So now you move forward to the next period. I 13 guess there will be another mix and it may be the same, 14 it may be slightly different. We don't know what the 15 mix in terms of customer demands, what you are 16 replacing, what you are replacing them with, but the 17 rates here reflect a mix of actions. In the next period 18 you are going to have a different mix of actions. There 19 is no reason why that mix should give you a different 20 set of expenditures, other than it is going to be higher 21 because of inflation which you recognize that it is 22 allowed under the IPI. So that's where I have a 23 problem, Doctor. 24 MR. BOLLING: What I will try to do because it 25 is clear to me that I am not making clear what my views 26 are to you. I will try to memorialize that better in 27 the text that we will soon submit. 28 Let me try one more scenario. If we take a 390 DTE/PROBYN 1 distribution circuit that isn't there today and then we 2 put it in tomorrow because a new subdivision comes in 3 and we decide we can't tax the existing distribution 4 system, who pays for the backbone of that system? 5 MEMBER VLAHOS: Sir, when the rates were set 6 there was another subdivision that was being built and 7 the rates reflected that additional expenditure, that's 8 my point. 9 MR. BOLLING: But the only way depreciation 10 could conceivably capture all of that in the long run is 11 if you close the subdivision down at the time you open 12 this one up. 13 MEMBER VLAHOS: Okay. I guess -- 14 THE PRESIDING MEMBER: There is a slight 15 difference. There are another 30 customers who obtained 16 rates who are then contributing to the depreciation 17 which is not going to the old plant. It's going to the 18 new plant and what you are saying is that that 19 depreciation has to cover the connection costs and 20 that's the only thing it covers. It doesn't cover the 21 contribution towards the system at all. 22 MR. BOLLING: That's correct. 23 THE PRESIDING MEMBER: That's where my 24 difficulty arises because if you have a contribution 25 policy which is defined by determining that this is how 26 much you can pay to attach a customer. If it costs more 27 than that amount that has to be a contribution and then 28 that's built into it, probably some allowance for 391 DTE/PROBYN 1 support of the base system. 2 I mean it depends what your contribution 3 policy is, how much of a growth factor you may or may 4 not need. 5 MR. BOLLING: It's getting late into the 6 evening and it's clear to me that -- by the way, I 7 apologize. I will take the ownership of the deficiency 8 of selling the argument. 9 What I will propose to do though is we will 10 submit, as you suggested to the previous speaker, a 11 specific example that illustrates how this cost will not 12 be covered and show the relatively detailed managerial 13 accounting to make the point, if that works for the 14 Board. 15 MEMBER ZERKER: You said a couple of things 16 about when you were bringing up the productivity factor 17 and your concerns with it. One of them was that you 18 weren't too happy or impressed with the figure they were 19 using or the methodology for labour. 20 MR. BOLLING: Yes. 21 MEMBER ZERKER: And so I am throwing that one 22 back to you to find out why. 23 MR. BOLLING: Sure. 24 MEMBER ZERKER: The other one was the CPI 25 curve and the IPI curve are so different. I think 26 perhaps Mr. Vlahos asked you, but I wasn't clear on your 27 answer. Do you not think that the fact that the CPI 28 curve in Canada does not include capital? 392 DTE/PROBYN 1 MR. BOLLING: I'm sorry? 2 MEMBER ZERKER: The CPI curve does not include 3 capital. The Canadian statistical methodology does not 4 specifically include capital, except as it is perhaps 5 embedded into products. 6 MR. BOLLING: I am not sure if you are asking 7 me a question, Doctor, forgive me. 8 MEMBER ZERKER: I am asking you if that could 9 make the difference. 10 MR. BOLLING: My first blush reaction to that, 11 it would seem, if I understand what you are saying -- if 12 I understand you properly, it would seem as if you would 13 expect a different effect out of the curve. 14 You see, what we have is a CPI curve that is 15 escalating and we have a volatile kind of downward 16 sloping IPI curve. 17 MEMBER ZERKER: Right. 18 MR. BOLLING: Now, if I pull the capital out 19 of the CPI curve -- I am sorry, if I add capital to the 20 CPI curve it makes those curves look even more 21 dissimilar, it seems to me at first blush. 22 If I add to that curve, it's an exponential 23 curve, if I add to that -- 24 MEMBER ZERKER: Actually, the alternative 25 would be to withdraw capital from the IPI curve and that 26 will make -- 27 MR. BOLLING: No. They get more distant. To 28 the extent that you pull those factors up -- you see, if 393 DTE/PROBYN 1 I have one curve going like this, kind of a power curve, 2 downward sloping, and you have another curve that starts 3 looking exponential as a time series basis curve. 4 To the extent that I pull variables out of one 5 that is in the other I am going to widen those curves. 6 MEMBER ZERKER: Fine. Then in which case 7 which is the more appropriate? 8 MR. BOLLING: Doctor, let me share with you, I 9 don't know. I will tell you this, I start with the 10 mindset of trying to conceptually justify why the IPI 11 should be different from the CPI when they are 12 different. 13 When I looked at these curves they were so 14 wildly dissimilar I can't reconcile it. What it tells 15 me, there is a contaminant in the approach to begin with 16 and that's what I discussed earlier, that there is 17 efficiency woven into that escalation. That's one of 18 the areas of contamination. 19 What I would do if I were charged with 20 resolving this issue, I would go back to more reliable 21 indices. I would use manufacturers, forward price 22 curves and actually history curves to get at this issue. 23 I would not look at the data sets that were examined and 24 then purport to this Board that they represent going 25 forward escalations. They simply do not, in my opinion. 26 MEMBER ZERKER: How about labour then? 27 MR. BOLLING: I'm sorry? 28 MEMBER ZERKER: How about the labour then? 394 DTE/PROBYN 1 MR. BOLLING: The concern that I have with 2 labour and let me be clear on this. The same issue 3 occurs in labour and when you are dealing with quantity 4 of labour, which they did, it raises issues of the 5 efficiency rather than price escalation, so that 6 contaminant is there. 7 But there is another issue on labour that I am 8 unsettled with and you may have a more comfortable 9 feeling than I. I asked the question of myself: Is the 10 line crew average labour rate a good proxy for the 11 corporation's labour? And I answer: I don't know. It 12 could be suffered to contract. They could be under 13 greater labour pressures than the balance of the labour 14 force. I just don't know whether it is a good proxy. I 15 am not sure why one would want to use that. 16 If I were speaking to the consultant I would 17 say why did you want to use that? Why wouldn't you use 18 our labour rate and forget about the quantity of labour? 19 Right? I mean, I can take the total labour 20 costs and divide it by 2,080. 21 By the way, the other thing I did is they used 22 not full-time equivalent. They used full-time positions 23 and I am left asking why did they do that? It seems to 24 me that those three components I talked about, those 25 three ways of looking at that labour number could 26 seriously introduce bias into that statistic. 27 So I look at that and, Doctor, I guess the 28 conclusion that I draw is I look at what I view to be 395 DTE/PROBYN 1 very unusual algebra to get at those numbers and then I 2 look at the very unusual behaviour of those curves and I 3 am left saying I don't know. I think it needs a lot 4 deeper dive. That's my impression, Doctor. 5 MEMBER ZERKER: I appreciate that. Thank you 6 very much. 7 MEMBER VLAHOS: Doctor, just one last question 8 on the material that you handed out, dated August 12. 9 MR. BOLLING: Yes. 10 MEMBER VLAHOS: You make a statement that the 11 Handbook, all it does it take care of the upside that 12 may be produced, but disregards the firm's downside 13 exposure. I have a note here, why shouldn't it? Can I 14 get you to respond to that please. 15 MR. BOLLING: Sure. Let's first of all make 16 we are on the same plane with respect to rents. There 17 are some rents which would be inappropriate and which 18 lend themselves to good regulatory control. These are 19 largely monopoly rents. 20 There are other rents, entrepreneurial rents, 21 that in my judgment should be unbridled. The 22 complexity -- I concede to the issue that we are dealing 23 with here is we have this crazy good that is partly 24 public and partly economic and partly on some kind of 25 technology evolution, and so it is a difficult call. 26 In my view, however, and I must tell you the 27 context in which it was presented I thought would be 28 offensive to MEUs. Did I say that right, municipal 396 DTE/PROBYN 1 electric utilities? I get LDC and MEUs all spun around. 2 But what they refer to as a dead zone -- now, 3 the context in which I am most familiar with the use of 4 dead zone is if there is noise and data. Usually, two 5 parties who are uncertain with what risk position they 6 want to take, say, look, this dead zone stuff we don't 7 know what's causing it. We don't know whether it is 8 utility behaviour or weather or capital cost. We have 9 no idea. 10 So within this dead zone we agree to do 11 nothing, but if it goes away up here we agree that's 12 wrong and we are going to harness it and bring it back 13 down. If it goes away down here, we know that's wrong 14 and we are going to bring it back up. 15 Here we have a dead zone that is only dead in 16 one direction and it strikes me that that is just wrong 17 minded. What my belief is and, in fact, the way I would 18 suggest the Board deal with this is not in any 19 over-arching way that undoes all of the good work that 20 has been done, but earlier when we talked about that 21 matrix of the reward and the performance factor, my 22 advice would be add 25, add 50 basis points to the upper 23 end of that to deal with this issue. 24 I realize that it would be imprudent for the 25 Board and certainly in the roll-off of these markets to 26 completely unbridle the distribution system in terms of 27 its returns. I would never suggest that. I think that 28 would be reckless on your part and it would be reckless 397 DTE/PROBYN 1 on my part to suggest it or even suggest such a thing. 2 But I do think that the system is absent 3 pushing the real entrepreneurs for those stretch kinds 4 of efficiencies that you want out of the system. This 5 system doesn't do that, and so my advice would be to 6 contemplate the changing upper limit by allowing those 7 stretch efficiencies through adding some basis points to 8 the matrix. 9 MEMBER VLAHOS: So if you split the upper 10 limit then you have no concern about the absence of a 11 downside exposure. 12 MR. BOLLING: I think that's a legitimate way 13 to view this. By the way, there is some downside 14 exposure and that's the Z-factor. To my humble way of 15 seeing it, I would be very comfortable if that were the 16 response that you would take to this issue. I would 17 personally be very comfortable. 18 MEMBER VLAHOS: Sorry, Doctor, you have lost 19 me. 20 MR. BOLLING: If you adjusted basis points on 21 the upside of the performance factor ROE matrix and then 22 left the Z-factor in for the exogenous downside 23 possibilities, I think that's a legitimate management 24 risk for utilities to take and it properly encourages 25 those stretch entrepreneurial behaviours that you want. 26 MEMBER VLAHOS: But begs the question as to 27 what is an appropriate bend. You say that whatever the 28 bend is here it is not good enough and you have to give 398 DTE/PROBYN 1 it some downside production. If you stretch it a bit 2 more, then we don't need that protection. So what is 3 the magic number? 4 MR. BOLLING: Of course, it would be foolish 5 for me to say that there is a magic number. I don't 6 know what that magic number is, but what you have done 7 is erected a system that will produce average industry 8 returns for top performers. To my way of thinking that 9 constrains the efficiencies that you could otherwise get 10 out of the delivery system. That is really the advice 11 that I'm giving. 12 MEMBER VLAHOS: Thank you very much. 13 Thank you, Mr. Chairman. 14 THE PRESIDING MEMBER: I was just asking what 15 was your view on having an earnings sharing type 16 arrangement as opposed to an ROE cap? There was some 17 discussion by one of the parties this morning about 18 having a sort of increasing sharing opportunity to 19 higher the productivity factor adopted by the utility. 20 MR. BOLLING: Let me respond to that 21 generically. The devil resides in the details of all of 22 these. There is very often times distance between the 23 policy ambition and the specific touchdown points of 24 policy, but generically I think that's a fine approach. 25 I think the sharing above the average industry return is 26 a very fine approach in the short run to encourage those 27 kinds of entrepreneurial behaviours. 28 THE PRESIDING MEMBER: And so to increase the 399 DTE/PROBYN 1 sharing to the company, the higher the productivity 2 factor goes so the stretching -- the further you 3 stretch the higher a return you get? 4 MR. BOLLING: Yes, and then share that. I 5 think that is completely reasonable to do that. 6 Again, let me do mention -- we discussed it a 7 little earlier, but when one realizes that the outputs 8 associated with a given efficiency input diminish over 9 time, it is a way to recognize that. It doesn't take 10 the municipal utilities, at some priorital optimal 11 point, they say, "We are done with efficiency 12 improvement because there is too much risk for that 13 level of return." What that does is it really opens up 14 -- it opens up the horizon for efficiency improvements. 15 So I think that is an excellent idea, 16 Mr. Chairman. 17 THE PRESIDING MEMBER: In the submission there 18 was some talk about pricing flexibility. I was 19 wondering, in your view, that if you provide pricing 20 flexibility, to what extent are the captive customers 21 going to suffer and what constraints could you put on 22 pricing flexibility? Because the concerns expressed 23 this morning that the only thing pricing flexibility 24 would provide is, in our view, to shift costs from the 25 non-captive to the captive customer. I believe that was 26 the position of one of the parties. 27 MR. BOLLING: That is conceivable. I mean, I 28 think the challenge of the Board is, at the end of the 400 DTE/PROBYN 1 day, however you arrive at rates, to be sure that you 2 have a good cost-based rate going in. Whether you do 3 that by proxy or with a more detailed bottom-up 4 approach, that is the challenge. 5 But the problem and, in my judgment, the 6 reason that the rate should be de-skewed, and you will 7 not like this if you come from a populist way of 8 thinking about this issue, but it is characteristic in 9 delivery systems, and actually in supply systems, for 10 residential consumers to not be paying their fair share. 11 They have very spiky loads, the installed costs for 12 serving that is very high, and the commodity is 13 temperature sensitive and otherwise irregular. 14 So what will happen as sure as the night 15 follows the day -- and, by the way, I would project, no 16 matter what short run position you take, the competitive 17 pressure in this business will cause those rates to take 18 their proper cost alignment over the long run. 19 Now, if you fail to do that in the short 20 run -- and, by the way, I don't know that there is a 21 problem, and if there is it may not be universal across 22 utilities, but conceptually what will happen, as sure as 23 the night follows the day, if you don't de-skew those 24 rates where they should be de-skewed, you will be 25 encouraging switching for those who have the -- and 26 everybody sooner or later will have the right to switch 27 and the ability to switch. The issue now is that there 28 will be suppliers who will want to serve those 401 DTE/PROBYN 1 industrial loads and the good, flat commercial loads. 2 To the extent that the residential rates don't properly 3 reflect their costs, you will encourage those other good 4 flat loads to switch leaving behind either strandedness 5 or greater cost burdens for the residentials. 6 So the market will, on its own accord, 7 regardless of any actions that any of us take in the 8 long run, straighten that out. But my suggestion is 9 that you try to do that in the short run. Use the 10 process that you have used, the top-down approach, as, 11 "Hey, here is the starting point unless you put forth 12 the effort to demonstrate that you have something better 13 that can be substantiated in any cost of service 14 proceeding." That is the advice that I would give. 15 THE PRESIDING MEMBER: Thank you. 16 You started your presentation, Mr. Allen, 17 talking about the various sort of performance measures, 18 performance indices. During the course of the 19 submissions people have talked about the momentary 20 interruptions and they have talked about including 21 something on worker safety, and they have also suggested 22 there should be some penalties for not filing data or 23 some sort of performance indicator that you have met 24 your data obligations. 25 I was wondering whether you had any comments 26 on adding those, whether they are measurably easy, the 27 last one maybe? 28 MR. ALLEN: Well, the first one, with 402 DTE/PROBYN 1 momentary outages, I guess from past experience we used 2 a methodology called -- looking at customer impact costs 3 as opposed to measuring customer minutes, because a 4 minute of interruption is not the same to each customer. 5 So some of the curves that you look at with a momentary 6 outage, there is a very distinct step function for that 7 momentary loss, particularly for an industrial plant. I 8 think including that is a very good measure for the 9 Board to look at how you include those momentary ones 10 because it is something that the distribution entity can 11 be in control of. 12 Again, the momentary ones, and I guess we are 13 back into our submission, they need to be very carefully 14 distinguished, is it something that the LDC had some 15 control over or is it something that was out of their 16 control, so distinguishing on those. 17 MR. BABAIE: There are some technology 18 distribution system reclosures dealing with those type 19 of momentary outages, but they are very limited. If you 20 are looking at outages in the order of, let's say, a 21 microsecond, those technologies cannot take care of 22 those. However, if in those microsecond outages impact 23 arrival -- speed arrives and basically influence -- 24 basically, introduces customer damage costs, so-called. 25 So it is just the technology is not there to 26 basically support that. However, I guess one could 27 argue that the momentary outages, if you tie it to the 28 customer interruption costs, then basically that is a 403 DTE/PROBYN 1 better measure than those conventional measures like 2 SAIDI, CAIDI, FAIDI. 3 MR. ALLEN: On the second point of the notion 4 -- I think back to more of our principles on should 5 there be something in place for the lack of filing of 6 data, it aligns with our principles to create a level 7 playing field that we certainly know that our client 8 would -- would have systems in place and would be 9 filing data. So it really puts them at a disadvantage 10 if you allow other utilities not to amplify all timely 11 data. So consistent with our principles, that would be 12 something we would support as well. 13 THE PRESIDING MEMBER: Then there has also 14 been a discussion about a failure to meet the 15 performance standards there should be some sort of 16 penalty. I don't know whether you have any suggestions 17 as to what sort of penalties -- 18 MR. ALLEN: We anticipated that those types of 19 penalties would come in Phase 2 of PBR. I think that is 20 why we put so much effort into the response to say that, 21 right now if you looked at those, typically, most of 22 those standards are relatively easy to meet and our 23 client is happy. It is the whole notion that somewhere 24 down the road there will be some teeth in those 25 penalties. If you are going to try to protect customers 26 and encourage that type of means of protecting 27 customers, ensuring they get that type of service, there 28 needs to be some teeth in it, so penalties seem to be 404 DTE/PROBYN 1 appropriate from the Board. 2 THE PRESIDING MEMBER: Do you have any 3 suggestions as to how the penalties might be 4 incorporated or included or what form they might take? 5 There we have a -- if you don't meet it you have to 6 report on how you are going to try and meet it, or the 7 compliance plan report. Certainly we heard this morning 8 from two parties, that there should be some form of 9 financial penalty. 10 MR. ALLEN: Yes. It is my sense that anything 11 other than just an economic penalty would be very 12 difficult to administer. You know, take the manager 13 behind the woodshed or something. 14 --- Laughter 15 MR. ALLEN: But it is my sense that the 16 utility, knowing the severity of those, and having those 17 well established out in advance, would be something that 18 would be certainly a target to recognize how important 19 meeting each of those targets was, simply filing the 20 information and/or meeting those performance standards. 21 So it would give the utility some type of benchmark to 22 say it is very important to meet that standard. 23 MR. BABAIE: I guess, mirrored to that penalty 24 at the same time is recognition and reward too. So you 25 want to have kind of a system there that promotes the 26 idea of the utilities taking basically proactive action 27 to improve their service reliability and the way they 28 serve customers. So, if you wish, it is both sides: 405 DTE/PROBYN 1 the reward and recognition at the same time as penalty, 2 too. So I don't know what is the plan there for the 3 second generation. 4 Basically, the handbook talks about some type 5 of compensation-based penalty for not meeting the 6 standards, but how about, you know, the reward, 7 basically, to meet those standards and at the same time 8 do more for the customers. 9 MR. ALLEN: One of the things that we have 10 kicked around, and I wouldn't say have come to a 11 conclusion on it, was a merit/demerit type point system, 12 that at the end of the year there would be a true-up to 13 say both a merit point or a demerit point is worth 14 X-number of dollars to the utility, and you put those 15 in. But if there is that type of penalty system, we 16 think it is very important that there is also 17 recognition or a reward for exceptional performance. 18 THE PRESIDING MEMBER: I think I asked about 19 whether or not it should include some sort of 20 performance measure related to employee safety and 21 health, et cetera. I don't know whether you had a view 22 on that. That was certainly raised by the Power 23 Workers' Union. 24 MR. ALLEN: Yes. It is interesting that one 25 of the criterias -- when we were looking at the 26 restructuring with our client, the whole notion of 27 safety came out of the very important element on the 28 decision on should the shareholder retain the utility or 406 DTE/PROBYN 1 sell the utility -- very strongly that that would be 2 it, a welcome measure. 3 THE PRESIDING MEMBER: But as a measure or is 4 it something that we just say, "Well, that is something 5 that they reported, what the safety is", or is it 6 actually measured? 7 MR. ALLEN: My sense with most of the measures 8 that the introduction of a measure as a reporting 9 requirement for a period of time so people get 10 comfortable with it before there is a penalty seems to 11 make a lot of sense. 12 So even as Phase 2 comes in or the 13 introduction, maybe there is a two year window where 14 that type of measure is introduced. So all the issues 15 that we try to define around definitions of each of 16 those elements, they can all be sorted out before there 17 is any real consequence with it. 18 MR. BABAIE: Whether there is a frequency or 19 number of those incidents or accidents, however you want 20 to define it, that could be very well their number of 21 measures. Right now Canadian Electric Association on a 22 Canada-wide basis, they are basically utilizing those 23 measures and benchmarks against the best performers. So 24 those measures could be adopted very well. 25 THE PRESIDING MEMBER: What would be the 26 reaction if we produced a league table showing all the 27 utilities and where they lined up in terms of meeting 28 all the measures, so the peer-pressure type discipline. 407 DTE/PROBYN 1 MR. ALLEN: Again, I think that is certainly 2 another way to recognize it. Interestingly, the MEA 3 introduced their performance benchmark back sometime 4 in -- 5 THE PRESIDING MEMBER: Ratios? 6 MR. ALLEN: Yes, in the early 1990s with all 7 the ratios. At that time I was a utility manager and so 8 everybody quickly looked out and said "Where do we stand 9 on the list?" There were very targeted action plans to 10 say -- even just producing that type of data to say, 11 "Well, we are number 12 on the list. We don't like 12 that, we want to be up here", does increase that type of 13 improvements. 14 MR. BABAIE: You know, I guess discussion of 15 the last time in the technical conference the staff 16 asked the same question, basically what our comments are 17 in terms of the benchmarking and those types of learning 18 from each other and I guess we fully support that idea. 19 Even not within the Canadian utilities, we have been 20 encouraged to go on an American basis looking at all the 21 good performers to see what we could learn from them. 22 Our clients are more or less doing that right now. 23 THE PRESIDING MEMBER: Ms Kwik, have you any 24 questions? 25 MS KWIK: Yes, we do, Mr. Chair. We need to 26 make a point of clarification. 27 Mr. Motluk. 28 MR. MOTLUK: I just wanted to clarify how 408 DTE/PROBYN 1 labour is treated in the price and productivity indexes. 2 The text in the technical document, the 3 productivity and price performance document is a little 4 ambiguous because it does say "number of full time 5 employees", but if you refer to the appendix on page 20 6 it is apparent from that spreadsheet that they are 7 actually using FTE employees. 8 Just if you were planning to do any further 9 work -- 10 MR. BOLLING: I appreciate that. Thank you. 11 MR. MOTLUK: -- just to clarify that. 12 DR. BOLLING: Great. 13 THE PRESIDING MEMBER: Thank you. 14 MS KWIK: Thank you. 15 That is all, Mr. Chair. 16 THE PRESIDING MEMBER: Thank you very much. 17 I hope you haven't missed your plane. That 18 was a very helpful submission. 19 Thank you. 20 We will assemble tomorrow at nine o'clock. 21 --- Whereupon the hearing adjourned at 1720, 22 to resume on Wednesday, October 6, 1999 at 0900 23 24 25 26 27 28 409 1 INDEX 2 PAGE 3 Hearing commenced at 0903 173 4 Presentation by Mr. Janigan and Mr. Todd 173 5 on behalf of VECC 6 Questions by the Board 181 7 Presentation by Mr. Stephenson on behalf of 222 8 Power Workers Union 9 Questions by Board staff 241 10 Questions by the Board 247 11 Upon recessing at 1130 254 12 Upon resuming at 1148 254 13 Presentation by Mr. White and Mr. Groulx on 254 14 behalf of ECMI 15 Questions by the Board 259 16 Luncheon recess at 1306 293 17 Upon resuming at 1405 293 18 Presentation by Mr. Poch and Mr. Hilson 294 19 on behalf of Energy Probe 20 Questions by the Board 307 21 Upon recessing at 1540 348 22 Upon resuming at 1556 348 23 Presentation by Mr. Allen, Mr. Babaie, 348 24 Mr. Bolling and Mr. Healey on behalf of 25 DTE/Probyn/Sault Ste. Marie 26 Questions by the Board 367 27 Questions by Board staff 407 28 Hearing adjourned at 1720 408 410 1 UNDERTAKINGS 2 3 NO. DESCRIPTION PAGE 4 2.1 Mr. White to produce summary, 291 5 as discussed 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27