1 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 Monday, October 4, 1999, commencing 22 at 0907 23 24 25 ORAL PRESENTATIONS 26 27 VOLUME 1 28 2 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 3 1 APPEARANCES (Cont'd) 2 ROGER WHITE ECMI 3 TOM ADAMS Energy Probe 4 MAURICE TUCCI MEA 5 STEPHEN CARTWRIGHT Enbridge Consumers Gas 6 BILL HARPER Ontario Hydro Networks 7 KEVIN BELL Great Lakes Power 8 GERRY DUPONT Nepean Hydro 9 RICHARD BATTISTA Union Gas Limited 10 BRIAN McKERLIE Municipality of Chatham-Kent 11 MICHAEL JANIGAN Vulnerable Energy Consumers 12 Coalition 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 4 1 Toronto, Ontario 2 --- Upon commencing on Monday, October 4, 1999 3 at 0907 4 THE PRESIDING MEMBER: Good morning. My name 5 is George Dominy. With me today are two of my 6 colleagues on the Ontario Energy Board. To my left is 7 Paul Vlahos and to my right is Sally Zerker. 8 We have with us some Board staff. We have 9 Judy Kwik, Keith Ritchie, and Stephen Motluk, who are 10 research and policy analysts. 11 We are sitting today to hear oral submissions 12 on the Board's RP-1999-0034 proceeding on an Ontario 13 Energy Board staff proposed Electricity Distribution 14 Performance Based Regulation Rate Handbook. This is the 15 next step in the process which started a year ago 16 leading up to the issuing of a Rate Handbook that will 17 guide utilities in preparing their rate applications to 18 this Board. 19 You should all have received a copy of 20 Procedural Order No. 4 and a letter from the Board's 21 Secretary, dated October 1, 1999, which outline the 22 general time frame and the order of presentations for 23 this part of the proceeding. 24 Following completion of the oral submissions, 25 parties may make final written submissions on the 26 proposals in the Draft Rate Handbook. Such submissions 27 must be provided to the Board by October 22, 1999. 28 As you will see, we will be hearing from a 5 1 number of parties over the next four days. We are 2 trying to meet a tight time frame and we appreciate your 3 co-operation in assisting us to meet these tight time 4 frames and help us to consider issues related to the 5 proposed Rate Handbook. 6 I am advised that DTE/Probyn, on behalf of the 7 Public Utilities Commission of Sault Ste. Marie, wish to 8 make a presentation in this proceeding but were not 9 placed on the list of presenters. Their presentation 10 has been scheduled for Tuesday afternoon, following the 11 presentation of Energy Probe. 12 Prior to the first presentation from Toronto 13 Hydro, Board staff wish to make a number of comments 14 relating to matters arising from the technical 15 conference. 16 Before you proceed, are there any preliminary 17 matters? 18 Then I turn it over to Board staff to make 19 their comments. 20 MS KWIK: Thank you, Mr. Dominy. 21 Good morning. Over the course of the 22 technical conference on Board staff proposed Rate 23 Handbook, participants have provided input that Board 24 staff believe will significantly improve the Rate 25 Handbook in its completeness and practicality. 26 In the summary Board staff would like to 27 address some of the issues raised by participants and 28 further clarify some of the responses made by Board 6 1 staff at the technical conference. 2 In terms of the market-based rate of return, 3 concern has been expressed that the change in costs of 4 debt is not reflected in the determination of the MBRR. 5 Board staff notes that the Rate Handbook needs to 6 clarify that the cost of current debt is included in the 7 current revenue requirement and that changes in the cost 8 of debt are reflected in the rate adjustment formula by 9 the costs of capital formula calculation in the IPI, or 10 the Input Price Index. 11 With regard to depreciation rates, the need 12 for consistency over time and between utilities was 13 implicit, in Board staff thinking, in the development of 14 the proposal. The Board's Accounting Procedures 15 Handbook for Electric Distribution Utilities states 16 that: 17 "Consistent with the CICA Handbook, this 18 AP Handbook does not provide prescriptive 19 guidance in terms of the amortization 20 methods to be used, the asset categories, 21 the estimated useful lives or 22 amortization rates. Instead, it is 23 expected that in the absence of an 24 objective study to support changes to the 25 current methods, lives or rates, 26 utilities will continue to use methods, 27 lives or rates consistent with past 28 practice." 7 1 It is further stated that the Board may review 2 the selected amortization methods, estimated useful 3 lives and amortization rates as it considers necessary. 4 Board staff believe that the continuation with 5 current methods, lives or rates with past practice is an 6 appropriate approach to depreciation schedules for the 7 electricity distribution utilities, subject to 8 consistency of application. 9 With regard to initial rates, several parties 10 have noted the importance of starting with rates that 11 are reasonable. In proposing that distribution 12 utilities that do not have a specific cost of service 13 and cost allocation study base their initial rates on 14 existing rates, the premise is that existing rates 15 appropriately recover costs from each of the rate 16 classes. 17 In the absence of such a premise, the 18 alternative is to require a utility specific cost of 19 service and cost allocation study prior to the 20 introduction of unbundled rates and the first term PBR 21 plan. 22 Recognizing the time limitation to market open 23 and the necessity for unbundled rates, this alternative 24 is not considered reasonable. Therefore, Board staff 25 identifies the need to adopt the stated premise as was 26 accepted in the past under the regulation of the 27 previous regulator. Had regulation continued under the 28 past regulator, the assumptions regarding cost 8 1 allocation would likely have continued as well. 2 For second generation, Board staff's proposal 3 is that rates should be based on the utility-specific 4 cost of service and cost allocation circumstances. 5 Likewise, a number of parties have questioned 6 the appropriateness of the use of a dated default 7 incremental distribution cost, the IDC, of .0062 cents. 8 Again, this value is proposed as a default value in the 9 absence of an alternative. 10 Concern has been expressed that there may be 11 significant rate impacts for some customers within a 12 rate class, as the distributors unbundle rates and move 13 to the new rate design. The suggestion has been made 14 that the Board should set caps on rate impact. 15 The Draft Rate Handbook points out that 16 distribution utilities consider rate impact associated 17 with market-based rate of return, transition costs and 18 extraordinary costs. It is suggested that a 19 distribution utility may wish to use a deferral account 20 to spread costs with accrued interest over future years. 21 The utilities are encouraged to consider these 22 options when the resulting increase and total bill is, 23 as an example, in excess of 10 per cent. These rate 24 impact mitigation options should also be considered for 25 rate impacts on customers within a rate class associated 26 with changes in rate structure. 27 As such, the proposal in the Draft Rate 28 Handbook is to make the distribution utility responsible 9 1 for rate impact mitigation. However, Board staff 2 recognizes that there should be rate impact reporting 3 requirements and that there is value to including a rate 4 impact assessment methodology in the Rate Handbook. 5 Therefore, it is suggested that rate impact 6 analysis be incorporated into Appendix A of the Rate 7 Handbook. 8 With regard to the minimum bill requirement 9 that Board staff had omitted to include in the Draft 10 Rate Handbook, it has been suggested that the use of the 11 distribution monthly service charge could be considered 12 for the minimum bill provision for the residential 13 class. 14 Board staff proposes that for the remaining 15 classes, the current approach to setting minimum bills 16 as described in the standard application of rates, or 17 the SAR, should be adapted for the unbundled rate 18 scenario. 19 As indicated in our opening remarks at the 20 technical conference, policies in the standard 21 application of rates that remain pertinent in the 22 application of the unbundled distribution rates need to 23 be incorporated into the final version of the Rate 24 Handbook. 25 Some of these policies may need to be adapted 26 to apply to the unbundled distribution rates only. 27 A number of participants have indicated that 28 the Rate Handbook does not provide sufficient or 10 1 adequate flexibility. 2 Within the proposal, flexibility is provided 3 in the distribution rate-setting process in a 4 distributor's capital structure, rate of return below 5 the cap, the use of its own data in the unbundling of 6 rates, in adjusting pricing baskets and in choice of 7 target TFP, or total factor productivity. 8 The Draft Rate Handbook provides guidelines 9 that recognizes that there can be large differences 10 among the 250-plus distribution utilities and that it is 11 likely that not all of them will be able to meet all of 12 the guidelines. 13 It is the intent that utilities that are not 14 capable of working within the guideline have the 15 opportunity for exemption from the guideline where 16 justification can be provided. 17 With regard to the justification, Board staff 18 notes participants' expression for the need of guidance 19 on the level of justification the Board might require. 20 Board staff recognizes that there are other 21 issues that may need to be considered. These include 22 the issue of using a three-year average rate of return 23 on equity for the three-year first generation PBR term. 24 It is Board staff's intent to complete these 25 outstanding matters that have been highlighted and place 26 them on our Web site to provide opportunity for comment. 27 Finally, Board staff would like to acknowledge 28 the valuable input that participants have provided 11 1 throughout the consultation process and would like to 2 express sincere appreciation for their conscientious 3 efforts. 4 Thank you. 5 THE PRESIDING MEMBER: Thank you, Ms Kwik. 6 Ms Kwik, I have a question with regard to the 7 rate impact analysis to be incorporated into Appendix A 8 of the Rate Handbook. 9 Is that one of the types of issues that you 10 believe you would put on the Web site and allow parties 11 to comment? 12 MS KWIK: Yes. 13 THE PRESIDING MEMBER: What are the other 14 issues that come to your mind, or the ones you have 15 raised, that you believe there may be comment? 16 MS KWIK: I think in transposing some of the 17 policies in the standard application of rates and 18 adapting them to the unbundled rate situation, there may 19 be some comments that participants would like to make on 20 those. 21 THE PRESIDING MEMBER: The other question I 22 had was with regard to the initial rates. I think, in 23 your statement, you said that the proposal was put 24 forward because there was not time to develop 25 cost-of-service-based alternatives. 26 If a utility has, in fact, got updated support 27 rate changes or wishes to change a rate because they 28 have a new type of service, how is that proposed to be 12 1 handled? 2 MS KWIK: The Rate Handbook, as it currently 3 stands, the proposal that Board staff has put forth, is 4 that any time a utility can provide justification it 5 should be considered if they would like to come outside 6 of the guidelines. 7 THE PRESIDING MEMBER: In terms of the 8 justification required by the Board, is this something 9 that Board staff would work with a utility that had a 10 specific application to guide them? 11 MS KWIK: I believe that could be an approach 12 to that. 13 THE PRESIDING MEMBER: Thank you, Ms Kwik. 14 Mr. Vlahos? 15 MEMBER VLAHOS: Ms Kwik, I just want to 16 clarify something. 17 You spoke of the three-year averaging on the 18 rate of return. I just want to make the links to part 19 of 3.3.5 in the Handbook, which is entitled, "Potential 20 Rate Impacts". 21 MS KWIK: Yes. 22 MEMBER VLAHOS: I also recall that in the 23 technical conference that Mr. King indicated that he can 24 bank any deficiencies in one year, to be carried in the 25 future. 26 MS KWIK: That's right. 27 MEMBER VLAHOS: So, is there a link there 28 between the three-year averaging on the regular term and 13 1 the banking issue, in your view? 2 MS KWIK: I'm sorry, I haven't given that any 3 thought, but possibly there is a link. 4 MEMBER VLAHOS: But you do recall, or the 5 record will indicate that Mr. King said that there will 6 be a -- 7 MS KWIK: Yes, I do. 8 MEMBER VLAHOS: -- banking provision which 9 would include any, I guess if I can call it, deficiency 10 in the rate of return to be implemented the first year? 11 MS KWIK: You are referring to the use of the 12 deferral account or -- 13 MEMBER VLAHOS: Yes. 14 MS KWIK: -- the rate adjustments? 15 Yes, I do. 16 MEMBER VLAHOS: All right. Thank you. 17 THE PRESIDING MEMBER: Dr. Zerker? 18 MEMBER ZERKER: Just one question. 19 With regard to the guidelines for 20 justification, are you going to develop a set of 21 guidelines for the justification and then put on the 22 (microphone interruption) individual basis? 23 MS KWIK: I think there are some circumstances 24 where it should be considered, at this point, for first 25 generation, on an individual utility basis. 26 MEMBER ZERKER: Thank you. 27 THE PRESIDING MEMBER: Thank you, Ms Kwik. 28 I believe the first presenters are Toronto 14 1 Hydro. 2 Would they please come forward. 3 --- Pause 4 THE PRESIDING MEMBER: Good morning. 5 Please carry on, Mr. Rodger. 6 PRESENTATION 7 MR. RODGER: Good morning, Mr. Dominy and 8 Members of the Board and Board staff. 9 My name is Mark Rodger, R-O-D-G-E-R. I'm 10 counsel to Toronto Hydro. With me, this morning, are 11 Mr. Richard Zebrowski -- that's Z-E-B-R-O-W-S-K-I -- who 12 is Manager of Rates and Regulated Services, and Ginny 13 Tam, T-A-M, who is Economist, Tariff and Pricing. 14 As a distributor of electricity, Toronto Hydro 15 continues to have a direct and important interest in the 16 development of a performance-based regulation approach 17 for electricity distributors in Ontario and we are 18 pleased to have the opportunity to make a presentation 19 to you, this morning. 20 Toronto Hydro has been pleased to participate 21 in this process of extensive consultation on PBR. We 22 have been involved in the various workshops and 23 information sessions that have been held over the past 24 several months; we have been involved in providing 25 information, as requested from the Board, as part of the 26 data collection; and we were also involved in the 27 technical workshops and the recent technical conference 28 hearing of evidence on this matter. 15 TORONTO HYDRO, Presentation 1 At the outset of our presentation, we would 2 like to express appreciation to the OEB staff and 3 consultants in their very significant efforts in the 4 development of a Draft PBR Handbook. 5 The restructuring of Ontario's electricity 6 sector is a significant event and the development of an 7 incentive-based mechanism to establish distribution 8 rates is a fundamental component of the new market 9 context. 10 Given this, Toronto Hydro believes that it is 11 crucially important to get this first step as right as 12 practically possible. 13 We recognize that an incentive-based rate of 14 return approach is entirely new to the electricity 15 distribution sector in Ontario. 16 Given this fact, and coupled with the reality 17 of the very challenging timetable within which Ontario's 18 electricity sector restructuring is to be completed, it 19 is clear to Toronto Hydro that the Draft PBR Handbook 20 before the Board is a strong effort to get all 21 distributors prepared for the new market environment. 22 The Draft Handbook, Mr. Chairman, is not a 23 perfect final version, nor should it be, in our view -- 24 and we will address some of our concerns in the latter 25 part of the submission. 26 It has been suggested, at the recent technical 27 workshops and technical conference, Toronto Hydro agrees 28 with others that the perfect is the enemy of the good 16 TORONTO HYDRO, Presentation 1 when it comes to a first generation PBR plan. 2 The proposed Handbook does achieve the 3 essential objectives that a first generation 4 incentive-based scheme should: It allows us to gain 5 sufficient experience with incentive-based regulation 6 while tempering the potential for negative or bad 7 outcomes. 8 As a result, this approach strikes several 9 balances for market participants, most importantly for 10 customers and for shareholders. The Draft Handbook 11 before the Board represents the initial step in an 12 evolving process that will take Ontario's electricity 13 distributors into a new era. 14 While some intervenors at the recent technical 15 conference indicated their position that stakeholders 16 must obtain greater assurances concerning components of 17 the analysis undertaken by the Board, Toronto Hydro is 18 less concerned about now undertaking further analysis, 19 which has been said is already very significant, but we 20 are quite concerned about any further delays in 21 finalizing the PBR Handbook. 22 In our view, a central goal is to avoid 23 establishing a PBR regime which gets things wrong at the 24 outset of the new market as opposed to striving to 25 getting things absolutely right on day one of that 26 new market. 27 Once again, Toronto Hydro submits that the 28 draft PBR Handbook is fundamentally a good starting 17 TORONTO HYDRO, Presentation 1 point for the development of incentive-based regulation. 2 Now, our particular concerns follow, 3 Mr. Chairman. 4 We underscore that these concerns are in the 5 nature of fine-tuning rather than redesigning the 6 Handbook and our comments will focus on the five 7 specific areas that follow. 8 One, the return on equity ceiling; two, the 9 return on equity averaging; three, rebasing 10 considerations; four, price cap versus yardstick; five, 11 cost of service study. 12 First the return on equity ceiling. 13 With respect to this ceiling or cap placed on 14 the return on equity we, like the Board indicated 15 earlier this morning, suggest a sharing mechanism which 16 will more accurately mimic competitive forces and result 17 in efficiencies both for shareholders and customers. 18 While a limit on returns may encourage a 19 distributor to push for and achieve efficiencies to 20 facilitate the maximum ROE cap, there may also be a 21 coincident disincentive to achieve even greater 22 efficiencies if a utility is not appropriately rewarded. 23 On the other hand, efficiencies beyond stated 24 thresholds can be encouraged and realized by utilizing a 25 sharing mechanism. Such a mechanism would reward those 26 distributors who are able to gain efficiencies beyond 27 the stated maximum ROE cap. The sharing aspect of this 28 mechanism would entrench a distribution of those above 18 TORONTO HYDRO, Presentation 1 maximum gains between customers and shareholders and 2 Toronto Hydro has suggested the sharing be done on a 3 50/50 basis. 4 Toronto Hydro submits that a sharing approach 5 would incent further efficiencies while ensuring that 6 consumers would also enjoy the benefits of such gains. 7 Therefore, Toronto Hydro recommends that this feature 8 should be incorporated into the first generation PBR 9 regime. 10 Two, return on equity averaging. 11 We are also concerned that if the ROE is 12 capped annually as opposed to be averaged over the term 13 of the PBR plan, then instability in both rates and 14 returns may result. 15 Given this concern, Toronto Hydro recommends 16 that ROE be averaged over a multi-year period, for 17 example three years. Such an approach would more 18 accurately balance large investments in one year with 19 productivity improvements in later years. 20 In this regard, in terms of large investments 21 we would note that the issue of capital expansion 22 guidelines did come up in the technical conference, but 23 it appears that that will be perhaps some months before 24 they will be forthcoming, so it is unclear how those 25 investments will fit into the first generation plan. 26 In addition, a multi-year averaging of the ROE 27 would also serve to dampen the inaccuracies associated 28 with annual energy loss calculations. Energy losses 19 TORONTO HYDRO, Presentation 1 represent a significant cost to distributors and, as 2 such, any errors or inaccuracies related to their 3 calculation would have a major impact on returns and 4 rates. 5 The issue of ROE averaging over several years 6 was raised at the recent technical conference. Although 7 Board staff did not indicate a position in this regard, 8 the Board staff's consultants did agree that this is an 9 issue which should be addressed by the Board when 10 reviewing the PBR Handbook. Board staff has clarified 11 that as well earlier this morning. 12 For the reference, Mr. Chairman, in the 13 transcript, this issue was discussed at page 141 of 14 Volume 1 of the technical conference transcript. 15 Three, rebasing considerations. 16 As we have indicated in previous submissions 17 to the Board on its proposed PBR approach, Toronto Hydro 18 is supportive of the Board's initiatives with respect to 19 incentive-based regulation in general and we are 20 supportive of the goals which underline the Handbook. 21 However, one of our other concerns involves 22 the development of the second generation PBR mechanism. 23 We understand that going into the second generation some 24 sort of adjustment or rebasing will be undertaken to 25 establish new benchmarks and criteria for PBR. 26 If the rebasing mechanism for the second 27 generation PBR scheme determines a baseline which 28 incorporates the total efficiencies gained in the first 20 TORONTO HYDRO, Presentation 1 generation PBR scheme, then there is a disincentive to 2 achieve these efficiencies all in the first generation, 3 since efficiency gains would be lost through a new lower 4 baseline in generation two. This could effectively 5 penalize those distributors that are more efficient and 6 may ultimately discourage maximum productivity gains 7 during the first generation PBR. 8 Toronto Hydro recommends that a mechanism be 9 developed to carry forward first generation gains and 10 share them between customers and their distributor. 11 This would not only encourage greater efficiency, but 12 would also create savings for customers and value for 13 shareholders. 14 The substance of this approach was raised at 15 the technical conference and Board staff's consultants 16 indicated that some form of recapture and sharing of 17 efficiency gains should be considered in the development 18 of the second generation of PBR. 19 For the Board's ease of reference, that 20 reference in the technical conference transcript are 21 pages 143 and 144, again of Volume 1. 22 Number four, price cap versus yardstick. 23 Toronto Hydro also recommends that for both 24 first and subsequent generations of PBR that Toronto 25 Hydro be subject to the price cap regime as opposed to a 26 yardstick approach. We submit that given the unique 27 character and size of Toronto Hydro it would be 28 extremely difficult to fashion a yardstick measure that 21 TORONTO HYDRO, Presentation 1 would accurately reflect the unique conditions and 2 factors that come into play in our specific business. 3 If a yardstick mechanism were applied to Toronto Hydro, 4 we believe the result would be inaccurate findings and 5 incentives not only for Toronto Hydro but also for all 6 others in the presumed peer group. 7 Finally, number five, cost of service study. 8 With respect to the incremental distribution 9 costs and the rate-setting mechanism, we support the OEB 10 proposed option which gives distribution utilities the 11 option to undertake and use their own cost of service 12 study to determine particular distributor cost 13 components and hence the establishment of initial rates. 14 Such an approach is fair to distributors by accurately 15 reflecting their true costs of doing business, while 16 also being fair to customers by establishing rates which 17 more accurately reflect the costs incurred in providing 18 them service. 19 In any event, where a particular distributor 20 seeks to use its own cost of service study the Board's 21 oversight will ensure that fairness and equity are 22 maintained in the rate-setting process. 23 In conclusion, Mr. Chairman, Toronto Hydro 24 would like to thank and commend Board staff and their 25 consultants for their significant efforts in getting us 26 all to this stage of the process. The Draft PBR 27 Handbook represents a very good first step forward 28 towards incentive-based regulation for electricity 22 TORONTO HYDRO, Presentation 1 distributors throughout Ontario. We are very pleased to 2 have been in involved in this process and hope that our 3 comments and recommendations will be of assistance to 4 the Board. 5 With that, we would be pleased to take any 6 questions. 7 Thank you, sir. 8 THE PRESIDING MEMBER: Thank you, Mr. Rodger. 9 Have Board staff any questions of 10 clarification at all that they would like to raise? 11 MS KWIK: No we do not, Mr. Dominy. 12 THE PRESIDING MEMBER: Thank you. 13 Mr. Vlahos? 14 MEMBER VLAHOS: Thank you, Mr. Chairman. 15 Mr. Rodger, I am going to have some specific 16 questions on what you said and then perhaps I will take 17 the liberty of asking you some general questions that 18 have arisen over the last week of the technical 19 conference. 20 Starting with the specifics, if you turn to 21 page 8 of your submission, sir, and that has to do with 22 the ROE ceiling. 23 I'm sorry, it has to do more with the sharing 24 mechanism that you propose. 25 If there would be a sharing mechanism in 26 place, then should this productivity/ROE menu survive, 27 in your view? 28 Anyone can answer that question, by the way. 23 TORONTO HYDRO 1 MR. RODGER: Yes, sir. 2 The answer is yes, that it should survive. We 3 see our proposal as something to supplement the 4 different menu of choices you are allowed to make on the 5 total factor productivity side. 6 Our view that this arose from that part of the 7 technical conference which various intervenors when 8 looking at the different menu of TFP that you could 9 choose and I believe the consensus seemed to be that 10 particularly for the higher numbers, the total factor 11 productivity, that that could very well be exceedingly 12 difficult to actually realize. 13 So when we suggest the sharing approach, the 14 goal is not to try and somehow provide another avenue to 15 capture that upper end rate of return, but for those 16 utilities that choose perhaps the developed value of 17 1.25, if there is an opportunity to within that seek 18 either even greater efficiencies, it would be a 19 safeguard that would benefit both shareholders and 20 customers by being able to do that within the TFP that 21 they do choose. 22 So it was really to try and provide an avenue 23 where efficiencies really could be extended to the 24 maximum amount that they could be under the default 25 value that is chosen. 26 And for those others that want to choose the 27 higher number, they should be free to do so. 28 MEMBER VLAHOS: Thank you. 24 TORONTO HYDRO 1 Of the ROE averaging, you heard my question 2 this morning of Miss Kwik and you indicated that -- and 3 I think that's a course Board staff have clarified and 4 you appreciated their clarification. Can you tell me 5 what you understand now as to where the ROE averaging 6 issue stands? 7 MR. RODGER: I think it arises from the 8 concern that when we file our first rate application 9 under this new regime there will still be many 10 uncertainties in terms of how all the pieces of the 11 market will fit together for distributors, and that by 12 having this averaging there will be a means to 13 accommodate some of the answers that are forthcoming in 14 the next two or three years which may have an upward 15 pressure on rates. 16 For example, we cite in our submission the 17 energy losses issue, often very difficult to calculate, 18 can't be determined precisely until after or perhaps 19 into the next rate year and by having this averaging 20 approach it would give us and all distributors some 21 flexibility in making adjustments to make sure that we 22 can achieve the returns that are allowed, but also to 23 accommodate surprises that will inevitably be 24 forthcoming. 25 So we see this as really almost like a 26 management mechanism to take us through the first 27 generation PBR and would be extremely helpful both for 28 customers and for shareholders. 25 TORONTO HYDRO 1 MEMBER VLAHOS: Thank you, Mr. Rodger. 2 But what is your understanding as to Board 3 staff's position on this? 4 MR. RODGER: I believe Board staff has 5 indicated that they are still considering it and there 6 will be some discussion and decision on this in the 7 final PBR handbook, but I don't believe they have made a 8 decision in this regard at this time. 9 MEMBER VLAHOS: Thank you, Mr. Rodger. 10 And again, the same question asked of Miss 11 Kwik. As you would read 335 of the handbook, entitled 12 "Potential Rate Impacts", would that in your view or in 13 Toronto Hydro's view capture your ROE averaging issue? 14 MR. ZEBROWSKI: What little quick thought I 15 have had about that issue, the deferral mechanism, as I 16 understand it, is mainly to allow a utility to set rates 17 below what the ceiling would be, what the rate cap would 18 be and, therefore, whatever lots and revenue they would 19 see by doing that they could then recapture in future 20 years. 21 On the other hand, I think the averaging 22 itself would help with smoothing out volatility issues 23 that may be out there. I think there are a number of 24 sources of these volatilities, one being losses, as Mark 25 just mentioned. 26 Another potential source of volatility is the 27 IPI performance from year to year, so that the averaging 28 would also help with these other issues. So utility 26 TORONTO HYDRO 1 could be at the capped level, operating at the capped 2 level in fact and still see swings from year to year 3 being fairly significant and the averaging would help in 4 that respect as well. 5 MEMBER VLAHOS: But I am not clear, Mr. 6 Zebrowski, as to whether the way now part of 335 is 7 phrased whether that would also capture the ROE 8 averaging as you propose it. 9 I understand that if you were to be on the top 10 of the range or the top of the ROE for a specific year 11 you still have the opportunity to use a deferral account 12 to capture some of the other costs, such as transition 13 costs if you wish now to pass them through one time. 14 But if you choose to be below the overall rate of return 15 allowed for a specific year, does the reading of that 16 paragraph -- is it your reading that you can bank it, if 17 you like, if you don't wish to go to the full ROE? 18 MR. ZEBROWSKI: Perhaps this is one area where 19 we do require further clarity in terms of how exactly 20 this paragraph is intended to work. I think we have 21 some ideas, but we basically do need further clarity in 22 this regard, yes. 23 MEMBER VLAHOS: Thank you. 24 Mr. Rodger, if you go to page 10 of your 25 submission, starting at the very bottom of that page, 26 where Toronto Hydro recommends that: 27 "A mechanism be developed to carry 28 forward first generation gains and share 27 TORONTO HYDRO 1 them between customers and their 2 distributor." (As read) 3 That's the rebasing issue. 4 Would your position be the same or would your 5 concerns be eliminated or mitigated if there was no cap 6 to ROE or there was a share mechanism? 7 MR. ZEBROWSKI: I think we see these as two 8 separate issues. In trying to create an incentive for 9 the utilities to increase productivity, I personally see 10 two possible impediments to utility furthering that type 11 of approach. One is a sharing mechanism that it will 12 free up the utility I think to try a little bit harder, 13 not be quite so afraid of going beyond what the cap is. 14 The other is not knowing really what is 15 entailed in the second generation of the PBR. That not 16 knowing how much productivity will be carried forward in 17 the second generation does create a risk for the 18 utilities and again it is just another impediment to the 19 utilities really trying as best as they probably could 20 have. 21 MEMBER VLAHOS: What is precisely the concern? 22 If you had a sharing mechanism and say for the purpose 23 of discussion that there will be a 50/50 sharing over 24 the top, then when we review matters for a second 25 generation PBR then I am not sure what assurances you 26 would like as to what the Board may do with what 27 MR. ZEBROWSKI: I think the share mechanism is 28 really for the three years of the PBR itself, so the 28 TORONTO HYDRO 1 utility has some assurance of how much it can recapture 2 within that three years. The rebasing is how much of 3 that return can the utility capture beyond the 4 three-year period. 5 I don't think we are proposing any figure at 6 this point in time, but just knowing how much the 7 utility can carry forward beyond the first three years 8 will help it in terms of its planning for investments 9 and so on, how much return it can expect back from those 10 investments, for instance. 11 MEMBER VLAHOS: Thank you. 12 On "Price Cut versus Yardstick" which appears 13 on page 11, Mr. Rodger, I am not sure what the 14 expectation is of Toronto Hydro. Do you want the Board 15 to comment in this decision on this specific request by 16 Toronto Hydro? I am just not sure what your expectation 17 is. 18 MR. RODGER: I think it is, in part, just to 19 alert the Board of Toronto Hydro's position on this 20 matter. 21 When Toronto Hydro staff were involved in some 22 of the workshops and the task force on yardstick, I 23 think going through that process it became I think very 24 clear to Toronto Hydro that that yardstick would be very 25 problematic. I think there was almost universal support 26 at the recent technical conference that yardstick was 27 the methodology that we would be working towards in the 28 second generation. 29 TORONTO HYDRO 1 That is, not Toronto Hydro's position. It 2 just, in our view, could not be done in terms of coming 3 up with a comparable system to Toronto Hydro for the 4 second generation. 5 So I think it was mainly in that context of 6 the general support of the others for the approach, but 7 to explain our reservations at this time. 8 No doubt we will deal with the specifics when 9 we do talk about the second generation plan, but we 10 thought we would put our position on the record at this 11 time. 12 MEMBER VLAHOS: All right. Thank you. 13 My last specific question is on the cost of 14 service study which appears on page 12 of your 15 submission. 16 Could you just help me, Mr. Rodger, or the 17 others on the panel, as to what specific components does 18 Toronto Hydro have in mind when you are talking about 19 distributor cost components that you may wish to put 20 forward pursuant to your own cost allocation study 21 exercise? Can you give us a list of those things? 22 MR. RODGER: Yes. I can maybe turn it over to 23 Mr. Zebrowski or Ms Tam, but I will certainly set one of 24 the contexts that we are concerned about. 25 Toronto Hydro has already started its review 26 on cost of service studies. I think it is fair to say 27 that this is a major undertaking for Toronto Hydro. 28 The issue in establishing initial rates in a 30 TORONTO HYDRO 1 cost of service study is: What methodology will Toronto 2 Hydro be allowed to use in terms of establishing that 3 incremental distribution cost? The default analysis 4 that the MEU study of the 1980s came up with was based 5 on the minimum system. That is one approach that could 6 be taken. 7 You could also, under a cost of service study, 8 take the maximum system approach, but it would come up 9 with a very different figure. 10 So one of our issues was to get direction 11 about whether the Board was expecting to see a 12 particular methodology being put forward or whether 13 utilities were free to put any methodology of their 14 choosing in coming up with an incremental distribution 15 cost as long as it could be verified by the Board. That 16 was perhaps the first broad issue, because, as I say, 17 depending on which methodology you came up with, you 18 come up with a very different cost. 19 It wasn't that perhaps one would be more 20 appropriate than another. It is just a different type 21 of analysis to come up with the results. 22 MS TAM: I think in our original submission we 23 pointed out the difference between the different cost of 24 service studies using the minimum system, which is 25 basically the embedded average cost. It could be quite 26 different if we had used a marginal cost pricing 27 approach. That may be more aligned with the IDC that 28 has been proposed. 31 TORONTO HYDRO 1 So we are just pointing out the differences 2 and the fact that it would have different rate impacts 3 in the future. 4 MEMBER VLAHOS: Okay. 5 So I have heard IDC. Can I just make a list 6 of what other components that you have in mind? 7 MR. ZEBROWSKI: That's really the principal 8 issue I guess at this point. 9 I mean, the whole approach in the cost of 10 service study, we will look at our own system and it 11 will be based on the design of our own particular 12 system, which is somewhat unique I think in the province 13 as well, and then go through the process of allocating 14 customer classes. 15 I'm not quite sure exactly how much I can tell 16 you in terms of the design elements and so on, but that 17 is the generalized approach to the cost of service 18 study. 19 MEMBER VLAHOS: Would it include depreciation 20 rates, for example? 21 MS TAM: Operating costs. Part of the 22 operating costs. 23 MEMBER VLAHOS: Would it include proposed 24 depreciation rates that may be different from the ones 25 that are applicable today? 26 MR. ZEBROWSKI: No. 27 MEMBER VLAHOS: No. Okay. 28 One moment, please. 32 TORONTO HYDRO 1 --- Pause 2 MEMBER VLAHOS: Mr. Rodger, I have completed 3 my specific questions to your submission. I do have 4 some general questions, but I would like to have my 5 colleagues continue with theirs and if there is any time 6 left then I will go with the general questions. 7 THE PRESIDING MEMBER: Dr. Zerker. 8 MEMBER ZERKER: I would like to get back to 9 the price cap versus yardstick that you have proposed 10 here for Toronto Hydro. 11 I was interested that you said that it was 12 almost universally appreciated that the second 13 generation is desirable to be a yardstick approach. 14 There are a couple of things that interest me. 15 One is: What is it that makes Toronto Hydro 16 so unique that it cannot operate within a yardstick 17 technique? 18 The second is: If indeed it is unique, how do 19 you conceive your organization to stand alone if indeed 20 the whole of the industry goes in the direction of a 21 yardstick approach? Would you see yourselves as having 22 a special deal, so to speak? 23 MR. RODGER: Mr. Chair, I'm going to ask, 24 Mr. Zebrowski to go through the specifics, but I could 25 perhaps respond by just looking at the Ontario context 26 and saying: Who would be the comparable? That might be 27 one way to illustrate the differences. 28 If we were looking at an Ontario-specific 33 TORONTO HYDRO 1 yardstick approach, then the only one that would be 2 comparable at least, perhaps in an initial assessment, 3 is looking at Servco, Ontario Hydro Services Company, in 4 terms of size, employees and so on. But then when you 5 go beyond that initial layer of kind of overall size, 6 and really the only other one in the province, but you 7 go beyond that, at every level it is really an entirely 8 different system. I think that comparison and the 9 differences just extend their way through the system 10 thereon in. Really it would be very difficult to come 11 up with another category given the specific systems 12 which now comprise Toronto Hydro. 13 So I think that's just the first theme, and 14 then Mr. Zebrowski will perhaps give you some more 15 specific elements of why Toronto Hydro is a very 16 different system. 17 MR. ZEBROWSKI: Just in general, I guess for a 18 yardstick mechanism, you do need a good comparable in 19 order to use that kind of a mechanism. We really don't 20 feel that there is anything out there that really is 21 comparable to Toronto Hydro. 22 As Mark just mentioned, size-wise Servco 23 probably is the closest to us but we all know that they 24 are primarily a rural distribution utility and we are a 25 very urban kind of a distribution utility. I think both 26 have very significant differences alone. 27 Even in terms of the MEUs, I think -- I mean, 28 just to run through a couple of things that would show 34 TORONTO HYDRO 1 Toronto to be a little unique, I don't think anybody 2 else in the province or any other city in the province 3 probably experiences the traffic congestion the way 4 Toronto does, for one thing. That creates a couple of 5 problems in terms of crews going out to job sites. 6 There are restricted hours in terms of when we can 7 actually operate on the streets, particularly main 8 thoroughfares. There are limited workdays because of 9 this. This all falls back on potential productivity. 10 We have a number of substations throughout the 11 city and there has always been a very great effort in 12 terms of blending those substations in with the local 13 neighbourhoods. That is a very expensive type of way of 14 doing business. 15 The design of our system is also somewhat 16 unique. In the downtown core we have what's called a 17 network system. It's almost a redundant type of a 18 system which creates a very high level of reliability 19 which you need in the downtown core. 20 In terms of our underground, we probably have 21 much more underground than what most other municipal 22 utilities would have. We have crews on 24 hours a day 23 to respond to customer problems. 24 Just in general, levels of system automation 25 and sophistication may tend to be somewhat higher I 26 think than most of the utilities. That is to give just 27 a flavour. 28 MEMBER ZERKER: How do you propose to resolve 35 TORONTO HYDRO 1 this condition of uniqueness within the context of the 2 PBR system that is emerging? 3 MR. ZEBROWSKI: Our feeling is that if we 4 continue under a price cap mechanism, that probably 5 would be the most appropriate mechanism to go forward 6 with. 7 MEMBER ZERKER: You don't see that as 8 problematic in relation to the rest of the industry. 9 MR. ZEBROWSKI: No. If we go back to the 10 original proposal that Board staff worked with, it was 11 to use yardstick mechanisms for the meeting of small 12 utilities throughout the province and to use a price cap 13 mechanism for the larger utilities. I am not sure how 14 many they included in that figure. 15 That was the initial intent, and we would 16 support that initial proposal. 17 MEMBER ZERKER: Thank you. 18 May I ask somebody on your panel to give me 19 some help on the averaging of ROE and how it would 20 perhaps affect that Table 4.1 which everybody knows so 21 well. 22 How do you see the relationship between your 23 proposal to do the averaging and this menu? Do you see 24 that as a problem? 25 MR. ZEBROWSKI: I don't see that as a problem. 26 In the supplement to the Handbook there was a section 27 that discussed annual returns, and the utility I believe 28 was going to be gauged against those annual returns to 36 TORONTO HYDRO 1 ensure that it wasn't exceeding its ROE ceiling. 2 So it is really replacing that part of the 3 Handbook. Instead of doing an annual check, it would be 4 a three-year check. So we would allow some averaging 5 throughout that period of time. 6 I really don't see it coming back and 7 influencing the table. 8 MEMBER ZERKER: Would then the PF factor be 9 chosen for the three-year period? 10 MR. ZEBROWSKI: The PF factor, I think the way 11 it is now, has to be selected for the entire three-year 12 period. 13 MEMBER ZERKER: That's right. 14 THE PRESIDING MEMBER: Thank you, Dr. Zerker. 15 I have a general question before I hand back 16 to Mr. Vlahos, and that is -- well, there are two 17 questions. 18 First, there have been a number of submissions 19 relating to demand side management and the effect the 20 PBR proposal may have on demand side management. 21 Toronto Hydro is quoted as one of the utilities that has 22 such programs. 23 Could you provide me with your comments on how 24 PBR may affect DSM. 25 --- Pause 26 MR. ZEBROWSKI: When we listened to the 27 previous DSM supporters, there was a question that came 28 back in terms of the appropriateness for an LDC to be 37 TORONTO HYDRO 1 involved in DSM programs. 2 DSM deals strictly with the commodity side of 3 the business going into the future. The principle now 4 is that the LDC is, in essence, totally removed from the 5 commodity. 6 So with that, just as a point of principle, it 7 created some confusion I guess in our minds as to is 8 there an appropriate tie-in because of that. 9 On the other side of it too, the LDCs are now 10 restricted from doing any further marketing programs. 11 In a way, you could look at DSM as being somewhat 12 related to a marketing program, whether it is negative 13 marketing or whatever. It is that type of an approach. 14 More than anything else, it raised the 15 question: Is there a tie between the utility and DSM 16 programs? 17 Putting that aside, if the Board feels that 18 yes, there is a role for the LDCs to play, I think the 19 LDCs would approach that strictly on a business case 20 standpoint; that they would have to look at the 21 resources required to go into this kind of a program, 22 the skill sets available that the utilities would have, 23 and the potential returns and investments that would be 24 required from the utilities. 25 If they felt that it made sense as a business 26 case, I think it would definitely be a fit. 27 Speaking for Toronto Hydro, I think Toronto 28 has a fairly good record of being involved in 38 TORONTO HYDRO 1 environmental matters and supporting these kinds of 2 programs and will continue to do that. Whether it is on 3 the retail side or on the LDC side, I am not quite sure. 4 I think there will be a role for Toronto Hydro to play, 5 but I think we will have to wait for the Board's 6 decision in terms of what the LDCs' role in that will 7 be. 8 MR. RODGER: I think there is also a question 9 that would have to be answered in terms of an amendment 10 to the market-based rate of return formula. 11 If you look at the submissions of the witness 12 for the Green Energy Coalition, I believe it was his 13 view that in any DSM scheme to go forward under the PBR 14 regime, the only way for it to work would be to leave 15 the distributors who implemented the programs revenue 16 neutral. So there would have to be some way to 17 recapture lost sales by the distributor. 18 I believe the approach from the Green Energy 19 Coalition was to essentially raise prices for everybody 20 else so that at the end of the day the distributor was 21 made whole. And that was seen as a necessary 22 requirement. 23 I think that the bridge from the principle to 24 the specifics would be through an amendment to the 25 formula. 26 THE PRESIDING MEMBER: Thank you, Mr. Rodger 27 and Mr. Zebrowski. 28 One other question. The Rate Handbook is out 39 TORONTO HYDRO 1 there. Have you, as a utility, experimented using the 2 Rate Handbook as it is currently structured and seeing 3 if you can come forward with a shadow rate proposal 4 based on it? 5 Have you tried to work it through, in other 6 words? 7 MR. ZEBROWSKI: Not really, no. We really 8 can't speak to any kind of rate impacts or anything of 9 that nature at the moment. 10 THE PRESIDING MEMBER: Thank you, 11 Mr. Zebrowski. 12 Mr. Vlahos. 13 MEMBER VLAHOS: Thank you, Mr. Chairman. 14 I just want to go back to some of the general 15 questions. 16 But before I do that, do I take it then that 17 other than the issues that you have set out in this 18 presentation this morning, you have no other concerns 19 that the Board should be aware of in terms of the 20 Handbook? 21 MR. RODGER: Yes, I think that is fair. 22 Toronto Hydro has now put in two submissions to the 23 Board, and a third being this one. 24 You will see that from the first submission 25 and the second submission there are some changes to 26 reflect clarifications, and I think the general message 27 is: These are some suggestions for changes, but we 28 think overall that it is a first generation plan within 40 TORONTO HYDRO 1 which we can work. 2 MEMBER VLAHOS: Mr. Rodger, can I take your 3 submission today as -- do I have to spend a lot of time 4 on your first submission, or does today's submission 5 cover all your concerns? 6 MR. RODGER: I think our view was that some of 7 the technical issues that we raised in the first 8 submission have been clarified. I think what we would 9 wait and do is review the transcripts from these various 10 oral presentations this week and then have our final 11 written submission where we will tie everything 12 together. 13 MEMBER VLAHOS: Thank you. Could you do 14 something for me. Could Toronto Hydro undertake to 15 provide the impact in terms of rate of return on common 16 equity of -- take 1 per cent change in the assumed 17 productivity factor or inflation factor and work the 18 impact on rate of return on common equity. 19 Could that be done, Mr. Zebrowski? 20 MR. ZEBROWSKI: Could you clarify that, 21 please? 22 MEMBER VLAHOS: Yes. I would like to know the 23 impact to Toronto Hydro's rate of return on common 24 equity if you assume a change in the productivity factor 25 in the PBR formula, or the inflation factor in the PBR 26 formula, and just take 1 per cent. 27 In other words, instead of having 1.25 per 28 cent as the base, take it as 2.25 or .25. It doesn't 41 TORONTO HYDRO 1 matter which direction. 2 I would just like to get an appreciation of 3 what the impact is on Toronto Hydro. 4 Does that clarify? 5 MR. ZEBROWSKI: If I understand you, you are 6 looking at what the total impact on a customer's rates 7 would be, on average? 8 MEMBER VLAHOS: What I'm looking for is the 9 change to the total revenue requirement that would 10 result from that change in assumption, and that change 11 in revenue requirement can be also transferred, in terms 12 of return on common equity. 13 MR. ZEBROWSKI: How much the return on equity 14 would change the -- 15 MEMBER VLAHOS: Right. On common equity. 16 Is that -- 17 MR. ZEBROWSKI: Yes. We could do that, yes. 18 THE PRESIDING MEMBER: For the sake of the 19 reporter, would you like to restate what it is I think 20 you have undertaken you would do. 21 MR. ZEBROWSKI: As I understand it, we are 22 looking at what is the increase to the -- 23 --- Off record discussion 24 MR. RODGER: Perhaps I could take a -- 25 We have undertaken to do an assessment of what 26 would be the impact on Toronto Hydro's total revenue 27 requirement and the impact on the return on common 28 equity if the default total factor productivity was 42 TORONTO HYDRO 1 changed by 1 per cent. 2 MEMBER VLAHOS: That's correct. 3 And I guess you can just do the productivity 4 factor. You don't need to, necessarily, do it for the 5 IPI or the inflation factor because I assume -- and I 6 can be corrected -- that the input will be exactly the 7 same. 8 MR. RODGER: If the IPI is supposed to track 9 the actual costs that utilities face, in any event, it 10 would pick up that inflation change. 11 MEMBER VLAHOS: All it is is a 1 per cent 12 change in one of the factors. 13 MR. RODGER: Yes. 14 THE PRESIDING MEMBER: This is an unusual 15 proceeding, but just to keep track, if you get a list of 16 these undertakings, let's call that No. 1. 17 MS KWIK: Yes. 18 THE PRESIDING MEMBER: Mr. Vlahos suggests 19 1.1, being first day first -- 20 UNDERTAKING NO. 1.1: Toronto Hydro to do 21 an assessment of what would be the impact 22 on Toronto Hydro's total revenue 23 requirement and the impact on the return 24 on common equity if the default total 25 factor productivity was changed by 1 per 26 cent 27 MEMBER VLAHOS: I have a few minutes, 28 Mr. Rodger, so maybe I can go to my general questions 43 TORONTO HYDRO 1 and the Chairman can cut me off when I'm over time. 2 Can you give me your understanding, or the 3 panel's understanding, as to what is it the Board will 4 need to approve going in into the PBR regime, to start 5 off with. 6 Do we approve a set of rate schedules for 7 Toronto Hydro? Or do we approve a ceiling of prices of 8 rates for different customer classifications and you 9 have the opportunity of flexibility of price anywhere 10 within that cap, or under the cap? 11 What is Toronto Hydro's understanding as to 12 what you will be receiving at the end of this process as 13 to going in rates? 14 As well as -- if you want to follow up on that 15 question, the second part of it is as to the next time. 16 Which is the first adjustment and the second adjustment? 17 MR. RODGER: I think our understanding of what 18 the Board will approve, from the statements of the Board 19 consultants at the technical conference, is that you 20 would be approving a series of upper rates and then, 21 from that maximum rate, Toronto Hydro, and all other 22 distribution utilities, would have the discretion, 23 thereafter, to charge that maximum amount, or lower 24 rates, as they saw fit, and that once the Board approved 25 that rate schedule, the utilities would not, thereafter, 26 have to come back to the Board for approval if they were 27 setting rates other than the maximum, as long as it was 28 lower -- for a lower rate. 44 TORONTO HYDRO 1 MEMBER VLAHOS: I want to make sure I 2 understand all this, so can we just go back. 3 You see it as the Board approving a set of 4 prices that would represent the ceiling for each rate 5 classification. That's going in into the PBR. And 6 those would have to be specific ceilings for each 7 system. 8 I sense your comments were that there would be 9 a ceiling for all systems, that would apply to all 10 systems. 11 MR. ZEBROWSKI: For the utility as a whole, as 12 we understand it. For the utility as a whole -- 13 MEMBER VLAHOS: That's right. 14 MR. ZEBROWSKI: -- there will be one price cap 15 for the entire utility, yes. 16 MEMBER VLAHOS: So that would be 250, whatever 17 the number is, of price caps for each of those customer 18 classifications? 19 MR. ZEBROWSKI: Well, this is one area we were 20 seeking clarification, but our understanding was that 21 there would be one overall price cap. In terms of how 22 it was defined, I think there was discussion along the 23 lines of it being a dollar-per-customer basis and that 24 figure would apply to the whole of Toronto Hydro and 25 each LDC would have its own price cap defined after 26 going through the MBRR formula. But there would be one 27 figure for the whole of Toronto Hydro is our 28 understanding. 45 TORONTO HYDRO 1 MEMBER VLAHOS: So that one figure per 2 customer for all of Toronto Hydro. 3 Then, how do you deal with the customer 4 classifications? Say you have two classifications: 5 residential and industrial. 6 MR. ZEBROWSKI: There, the Handbook talked 7 about keeping the different classifications revenue 8 neutral to where they are right now, unless, of course, 9 the utility can go through a cost of service study and 10 prove that there is cost subsidization which has to be 11 correct. But the intent, barring that, is to maintain 12 revenue neutrality within each class. 13 So, then, once you have that, then the price 14 cap can be redefined for each customer class in order to 15 maintain that revenue neutrality. 16 MEMBER VLAHOS: All right. So that's the 17 going in; that's the starting point. 18 MR. ZEBROWSKI: That's right. 19 MEMBER VLAHOS: That's your understanding. 20 Now, let's move into the first adjustment. 21 How do you see that thing working? 22 MR. ZEBROWSKI: Then the first adjustment 23 would apply to the price cap, so that dollar -- for 24 instance, if we used the dollar-per-customer figure, 25 that figure would be increased by the IPI and reduced by 26 the PF that the utility selected. That would create a 27 new price cap. Then the utility would have to adjust -- 28 well, assuming they were at the price cap, initially, 46 TORONTO HYDRO 1 then they would have to readjust their customer classes, 2 again, by the change in the overall price cap. 3 MEMBER VLAHOS: Okay. But you will no longer 4 be constrained, in terms of revenue neutrality? All you 5 have now is you have, again, a price, a dollar per 6 customer, but it would be a new one, let's say, a higher 7 one. What flexibility, now, do you have, in terms of 8 pricing within the different rate classifications? 9 MR. ZEBROWSKI: Well, the Handbook also allows 10 price flexibility, in which case, there is allowed to be 11 some movement in a shifting of revenue between 12 classes -- and they used a figure of 5 per cent, I 13 believe, in the Handbook. 14 MR. RODGER: Five per cent maximum per year 15 MEMBER VLAHOS: So that at any point in time, 16 you would have a -- let's say, in the first year, you 17 may have the residential class subsidizing the 18 industrial to the tune of 5 per cent? 19 MR. ZEBROWSKI: It's our understanding that, 20 yes, that's permissible now, yes. 21 MEMBER VLAHOS: And the second year, then, you 22 add another 5 per cent? 23 MR. ZEBROWSKI: That's our understanding as 24 well, yes. 25 MEMBER VLAHOS: There has been a lot of 26 discussion, as I understand it, as to the kinds of 27 things that would come out if one assumes that ownership 28 is the municipality as opposed to a privately-owned 47 TORONTO HYDRO 1 system. 2 What is your view as to what the Board ought 3 to consider in going forward as to whether the Board 4 should assume that some of the systems will be 5 maintained as municipally owned or should be in State B 6 and that should govern the Board's decisions as to 7 treating all systems that some day would be privately 8 owned? 9 MR. RODGER: I believe our response would be 10 that the issue of ownership, private or public, should 11 be irrelevant, that it is the end state that we are 12 seeking which is commercialization of the whole 13 electricity sector in Ontario, of which the distribution 14 utilities are one component. 15 MEMBER VLAHOS: So any discussion that a 16 specific utility does not need to go up to the cap, in 17 terms of rate of return on common equity for example, 18 that should not even be a consideration for this panel, 19 that its decisions -- its deliberations should be driven 20 by private ownership as the end state? 21 MR. RODGER: Yes. And, as we say, our 22 understanding is that all utilities and their municipal 23 or private shareholder owners will thereafter determine 24 what level of return they direct the company to 25 undertake. 26 MEMBER VLAHOS: Okay. Thank you. 27 --- Pause 28 THE PRESIDING MEMBER: Mr. Vlahos has some 48 TORONTO HYDRO 1 additional questions, so we are going to run a little 2 behind on this particular panel. 3 Go ahead, Mr. Vlahos. 4 MEMBER VLAHOS: Panel, I'm going to turn to 5 the inflation factor for a minute. 6 Can you help me, from Toronto Hydro's point of 7 view, from an internal management planning and a 8 regulatory administration point of view, regulatory 9 administration within Toronto Hydro as well as the Board 10 as you perceive it, are there any benefits to having a 11 well-recognized, well -- easy to access CPI as opposed 12 to an IPI as the inflation factor in the PBR formula? 13 From a planning point of view, can you help me 14 understand that? 15 --- Pause 16 MR. ZEBROWSKI: There is not really too much I 17 can say on that, except that maybe -- I mean, we are 18 dealing with past -- or numbers that reflect past 19 history, the only difference being, I believe, that 20 there is a forecast given for CPI and that would 21 potentially help some in the financial planning. 22 We definitely wouldn't have that same type of 23 thing with the IPI. So that may be the only difference. 24 Other than that, I really couldn't give you 25 anything more on that. 26 MR. RODGER: Just for your information, I 27 think one matter that is important, which again did come 28 up at the technical conference in the questions put to 49 TORONTO HYDRO 1 the Board staff consultants, would be that all 2 distribution utilities in Ontario would be receiving the 3 type of information and the calculations from the Board 4 as part of the final Handbook that would allow each 5 utility to calculate their own IPI under this Handbook. 6 MEMBER VLAHOS: Calculate its own IPI? It 7 would not be the same IPI for all utilities? 8 MR. RODGER: No. The distributor-specific IPI 9 could be a different number than that used for the 10 group, but I think it was felt that that was important 11 that each utility could do that on its own. 12 MEMBER VLAHOS: Ms Kwik, can you confirm that? 13 MS KWIK: I think the distinction that 14 Mr. Rodger is trying to make is that the IPI that would 15 be used in the rate adjustment would be based on a 16 number that would be derived from the 49 utilities on 17 which we had the data. So it's an aggregate number. 18 But there would also be the possibility for 19 each individual utility to be aware of what its distinct 20 input price index would be, which could fit into the 21 range of those 49 utilities, possibly. 22 MR. RODGER: Also, if you were above or below 23 the IPI, that would also have an effect on your ultimate 24 return. There is another incentive, if you like, to do 25 better than the IPI. 26 MEMBER VLAHOS: I guess I'm interested in the 27 implementation of the PBR. What number would -- Toronto 28 Hydro, you are saying, could use its own number, or 50 TORONTO HYDRO 1 would use its own number, not the aggregate average 2 IPIs? 3 MS KWIK: I think the reason we brought up 4 this issue of what your own distinct IPI is is to 5 demonstrate that in fact in terms of yardsticking -- 6 there is a yardsticking component to the proposal, and 7 that is: If you can do better than the aggregate IPI 8 then your bottom line would be improved. 9 MEMBER VLAHOS: That's right. So if the 10 number is 1, but due to good management my own number is 11 .5, then I'm better off, I'm making some extra profits. 12 But what number would Toronto Hydro use if it is .5 13 instead of 1 for purposes of setting its rates? 14 MS KWIK: For rate adjustment purposes it 15 would be using the aggregate IPI that the Board would 16 provide. All utilities will be using the same IPI in 17 their formula. 18 MEMBER VLAHOS: Thank you. 19 That is not what I understood from Mr. Rodger. 20 Maybe I misheard, but I thought you indicated that you 21 would use your own IPI. 22 MR. RODGER: No, I'm sorry. Ms Kwik is 23 correct. 24 My issue was from the planning point of view, 25 it will be very helpful for utilities to have that 26 information that they can determine their own IPI so 27 they can compare it to the aggregate number. 28 I'm sorry if I wasn't clear. 51 TORONTO HYDRO 1 MEMBER VLAHOS: All right. Thank you. 2 I have just run out of time so just one last 3 question, panel: What Ms Kwik mentioned this morning 4 about when she clarified what the current rates reflect 5 by way of debt. As I understood it she indicated that 6 the current rates do reflect the embedded cost of debt 7 and the IPI, the way it is structured is not only does 8 it incorporate or reflects changes in the labour and 9 material but also changes in the cost of capital, and I 10 took that as cost of debt. Is that your understanding? 11 MR. ZEBROWSKI: Yes, there is the -- for the 12 capital component within IPI there is the carrying cost 13 which relates to the cost of debt, yes. 14 MEMBER VLAHOS: All right. So when we say 15 about the capital component, since we are already taking 16 care of the return on common equity, then all that is 17 left is debt? 18 MR. ZEBROWSKI: Yes. Within the LDC, yes. 19 MEMBER VLAHOS: Are you aware of any 20 criticisms that have been voiced in this technical 21 conference about the volatility or the appropriateness 22 of that component of the IPI? 23 IPI has three components, as I understand it, 24 labour, material and debt, and the debt component is the 25 one that appears to be problematic for some parties. Do 26 you have any thoughts on that? 27 --- Pause 28 MR. ZEBROWSKI: Yes. That was an area that 52 TORONTO HYDRO 1 was pointed out with the cost of capital I believe. 2 What they found was that the cost of capital 3 changed -- or could change significantly from one year 4 to the next, which in the end created a fair bit of 5 volatility on the IPI figure. That, of course, created 6 some concern. 7 Our response to that is that if we go with the 8 three year averaging it will tend to help smooth that 9 effect out, and I think that would probably be 10 sufficient in terms of addressing that problem. 11 MEMBER VLAHOS: What causes the volatility, 12 Mr. Zebrowski, in your view? It is change in interest 13 rates times something. What is it? Is it the change of 14 interest rates or the something that is multiplied by 15 the change? 16 MR. ZEBROWSKI: Well, I'm not exactly clear on 17 everything that went into the calculation, but my 18 understanding of it is that the interest rates when they 19 are quite low don't have to change by very much, but 20 with a small change you would in fact see a large 21 percentage change on the interest overall. That is what 22 creates the volatility. 23 MEMBER VLAHOS: Is that because -- and again 24 you may not know the answer to this question. Is that 25 because it applies to all of the embedded debt that is 26 within the company? 27 MR. ZEBROWSKI: I don't think it relates to 28 the embedded debt. It is how much capital the utility 53 TORONTO HYDRO 1 is carrying, which really more closely relates to the 2 rate base I believe. I am not quite clear on it anyway. 3 MEMBER VLAHOS: Thank you. 4 Thank you for those answers, panel. 5 Thank you, Mr. Chairman. 6 THE PRESIDING MEMBER: Any additional 7 comments, Miss Kwik? 8 Questions of clarification? 9 MS KWIK: Mr. Motluk would like to provide 10 some clarification on this issue of the capital included 11 in the IPI, if he may. Thank you. 12 MR. MOTLUK: I would like to clarify that to 13 calculate the capital portion of the IPI calculation 14 what is represented there, to the best of my 15 understanding, and it is described in the paper on 16 productivity, is that the price increase on the capital 17 side represents the change in the prices of capital 18 assets, that is of hard capital assets. I am not 19 talking about financial capital, but hard assets like 20 transformers, wire, et cetera. 21 The change in the prices of those capital 22 assets adjusted for the cost of financial capital 23 represented by the Canadian long bond rate and also 24 depreciation, just to clarify that. 25 MEMBER VLAHOS: Mr. Motluk, if you would 26 clarify further for me, so that the two components, the 27 change in the price of hard assets and adjusted for 28 changes in what you said? 54 TORONTO HYDRO 1 MR. MOTLUK: Adjusted for the Canadian long 2 bond rate. 3 MEMBER VLAHOS: Right. So it captures the 4 changes in the Canadian bond rate from one period to the 5 next? 6 MR. MOTLUK: It actually captures what the 7 actual -- basically, it captures what the Canadian long 8 bond rate is as a measure of opportunity cost. So the 9 Canadian long bond rate is a rate of interest. 10 MEMBER VLAHOS: Right. But if I want to look 11 at an inflation factor I have to compare what the bond 12 rate was and what it is. 13 MR. MOTLUK: Yes. 14 MEMBER VLAHOS: So it captures the changes in 15 the bond rate from one period to the next period, from 16 one point in time to the next point in time? 17 MR. MOTLUK: My understanding of it and I 18 think the ultimate clarification would have to come from 19 Dr. Cronin, since he was involved in doing the 20 calculations and I was not. But as it is explained on 21 page 8 of the document entitled "Productivity and Price 22 Performance for Electric Distributors in Ontario", my 23 understanding is that the cost of capital represents the 24 change in the prices of capital goods that electric 25 distributors in Ontario would purchase, adjusted for the 26 actual price of capital which would be represented by 27 the Canadian long bond rate, which is an interest rate 28 and depreciation. 55 TORONTO HYDRO 1 MEMBER VLAHOS: All right. Thank you for 2 that. 3 THE PRESIDING MEMBER: Thank you very much 4 Toronto Hydro, Mr. Zebrowski, Miss Tam and Mr. Rodger 5 for your presentations. You have been very helpful. 6 Thank you. 7 The next presenter, I believe, is Pollution 8 Probe. We would ask them to come forward, if they 9 would. 10 Good morning, Mr. Klippenstein, and good 11 morning, Mr. Gibbons. 12 PRESENTATION 13 MR. KLIPPENSTEIN: Good morning, Mr. Chairman. 14 Good morning, Members of the Board. 15 I don't know if the Board has given 16 consideration to a break and, obviously, we are in the 17 Board's hands as to whether we should proceed now or 18 after a break. 19 THE PRESIDING MEMBER: I leave this with the 20 court reporter, but I felt if we could get the two 21 presentations done and then we would have a break 22 because there is another one to come before lunch and I 23 thought if we could get these two under our belt it 24 would help us. Is that all right with the court 25 reporter? 26 THE REPORTER: Yes. 27 THE PRESIDING MEMBER: Thank you. 28 Mr. Klippenstein. 56 POLLUTION PROBE, Presentation 1 MR. KLIPPENSTEIN: Thank you, Mr. Chairman and 2 Members of the Board, and good morning. 3 I am, of course, Murray Klippenstein, legal 4 counsel for Pollution Probe and with me is Mr. Jack 5 Gibbons, consultant to Pollution Probe. We thank you 6 for the opportunity to make a presentation this morning. 7 You, hopefully, have before you the text for 8 oral submissions by Pollution Probe which were filed. I 9 will not read those submissions, but they are available 10 for your reference and I will not depart from them too 11 much. 12 Pollution Probe wishes this morning to make 13 submissions on two issues related to the Electricity 14 Distribution Rate Handbook. Those two issues are the 15 question of energy efficiency or demand side management, 16 which has already been raised this morning and, 17 secondly, the issue of rate design. 18 Just by way of a thumbnail sketch of where 19 Pollution Probe is going with respect to the first issue 20 of energy efficiency, Pollution Probe is concerned that 21 the price cap regulation proposal for municipal 22 electrical utilities as proposed sets up anti-efficiency 23 incentives that are quite important and in doing so 24 conflicts with a number of important existing legal and 25 political guideposts. 26 On the second issue of rate design, Pollution 27 Probe's submission and concern is that the proposal to 28 significantly increase the fixed monthly customer charge 57 POLLUTION PROBE, Presentation 1 is based on some problematic facts and also will 2 introduce anti-efficiency incentives. 3 By way of summary, which I will elaborate on 4 later, Pollution Probe suggests that in order to correct 5 these problems MEUs should be allowed and indeed 6 encouraged to apply to the Board for an ability to use 7 one or more of the currently existing regulatory 8 mechanisms which enhance efficiency incentives. 9 Furthermore, on the second issue, Pollution 10 Probe will be submitting that a substantial increase in 11 the fixed customer charge should be postponed until the 12 facts can be clarified and until appropriate provincial 13 emissions caps can be put in place. 14 Perhaps the two key facts that I would 15 highlight for you before going into more detail is the 16 fact that the present proposal actually penalizes energy 17 efficiency and that penalty that they put on energy 18 efficiency is starkly out of place in Pollution Probe's 19 submissions. So whatever else in this complicated legal 20 and policy framework that is before you deserves your 21 attention, the penalization of energy efficiency does 22 stand out like a sore thumb in Pollution Probe's 23 submission. 24 The other point that I would highlight before 25 a more detailed description is that what's at stake here 26 is potentially hundreds of millions of dollars of 27 savings to customers over quite a few years and that's 28 without even calculating in the pollution costs that 58 POLLUTION PROBE, Presentation 1 result from inefficient use of energy. 2 To go into a bit more detail on the first 3 issue of Pollution Probe, which is the energy efficiency 4 issue, as the Board is aware, the proposal for price cap 5 regulation from the Energy Board staff would apply price 6 caps to MEUs. 7 Under price cap regulation, an MEU can 8 increase its profits in one of two ways. The first way 9 is to increase electricity sales or the second way is to 10 reduce its costs. 11 Whatever other benefits these two pathways 12 have, they tend to conflict with energy conservation 13 programs because energy conservation programs actually 14 potentially reduce profits on each of those two fronts, 15 namely by reducing sales, which is actually the intent 16 of some of these programs; and, secondly, by increasing 17 costs, because even cost-effective DSM programs do have 18 costs. 19 The written submissions provide some 20 transcript references for those two assertions, but 21 those are key. You have a potential conflict set up 22 between, on the one hand, the incentive under price cap 23 regulation to increase sales, and the intention of a DSM 24 program to actually reduce sales for the benefit of 25 efficiency and the environment. 26 Similarly, as I said, you have a conflict 27 between, on the one hand, the incentive under a price 28 cap regulation to reduce costs, with all the benefits 59 POLLUTION PROBE, Presentation 1 that produces; and, on the other hand, the conflicting 2 incentive under DSM programs to somewhat increase costs 3 to save energy. 4 I hasten to add after many, many hearings 5 before this Board I would submit that there is a great 6 deal of experience in sorting out which kinds of costs 7 or investments in DSM programs are now shown and known 8 to be cost effective and have financial benefits that 9 exceed their costs. 10 What this means is that, everything else being 11 equal, price cap regulations financially penalizes. It 12 actually penalizes an MEU that promotes the wise and 13 efficient use of energy. 14 I would submit that some of the testimony or 15 submissions from Toronto Hydro, which preceded Pollution 16 Probe this morning, exemplify, in a very useful way, the 17 point Pollution Probe has just made. 18 Mr. Chairman asked the Toronto Hydro 19 presenters about the fit between DSM programs and the 20 proposed regime as Toronto Hydro saw it. Interestingly, 21 the Toronto Hydro presenters identified exactly the two 22 problems we have just mentioned. 23 Mr. Rodger identified a concern with lost 24 sales due to DSM; and, Mr. Zebrowski pointed out, quite 25 properly, that Toronto Hydro would make its assessment 26 of DSM on a business case basis and would look at what 27 investments are required and resources are required. 28 So, in my submission, this is a perfect 60 POLLUTION PROBE, Presentation 1 example of exactly the dynamics, you know, predictable 2 and proper dynamics, that come into play under a price 3 cap regulation. And Toronto Hydro, using the criteria 4 presented this morning, would probably have a problem 5 initially with DSM programs because they would, if they 6 are doing their job, decrease sales over what they 7 otherwise would be and would inevitably incur some 8 costs. 9 If Pollution Probe's concerns are accurate, 10 and I submit they are, what should the Board do or 11 consider when it looks at this proposal before it? 12 Should it reject it or modify it? In my submission, it 13 should and I would like to point out four legal or 14 policy landmarks which suggest the Board would be 15 perhaps not making the most consistent decision if it 16 approved price cap regulation without some changes. 17 These are, as noted in the materials: the 18 provisions, firstly, of the Ontario Energy Board Act; 19 secondly, the existing ratemaking principles for gas 20 utilities; thirdly, considerations of the public 21 interest; and, fourthly, the recommendations of the 22 implementation task force. 23 The first legal guidepost that I mentioned is 24 the provisions of the Ontario Energy Board Act, which, 25 as you know, specifically state in section 1 that it is 26 one of the Board's objectives to facilitate energy 27 efficiency. 28 In my submission, it would be prima facie 61 POLLUTION PROBE, Presentation 1 problematic for the Board to implement a price cap 2 regulation regime which, as I have suggested a few 3 minutes ago, actually penalizes MEUs for the proper use 4 of DSMs, and that puts in place a driver directly in 5 opposition to an objective that the Board is supposed to 6 be advancing. 7 The second concern or guidepost, I have called 8 it, lies in a comparison with the Energy Board's 9 existing ratemaking principles in the gas utility 10 context. 11 As Members of the Board will be aware, in the 12 gas sector Enbridge Consumers Gas has established a 13 shared savings mechanism or an SSM which structures a 14 quite different incentive for the gas utilities and 15 gives the gas utilities a financial interest in helping 16 customers save money through energy efficiency. 17 This not only contrasts at a sort of policy or 18 intellectual level with the proposal before you but it 19 has a rather practical inconsistency on the ground 20 because, in a scenario with the present proposal, we 21 would have Enbridge Consumers Gas being financially 22 rewarded through the SSM for increasing the energy 23 efficiency of its customers in many of Ontario's major 24 cities, yet in those same cities under the proposal 25 before you the MEUs would be financially penalized if 26 they would reduce their customers' bills through energy 27 efficiency on the electricity side. 28 So you would, in a sense, have conflicting 62 POLLUTION PROBE, Presentation 1 incentives at work on the question of energy efficiency 2 all in the same important cities. 3 This, in Pollution Probe's submission, not 4 only is a glaring inconsistency and is arguably unfair, 5 it is certainly economically irrational to reward one 6 major player for reducing energy use and to penalize 7 another major player for doing the same. 8 The third guidepost, as Pollution Probe would 9 point out to you, is that to implement this penalty 10 incentive for MEUs on the efficiency question, has some 11 problems from the point of view of the public interest. 12 One is that the experience on the gas side has shown 13 that these efficiency programs can produce very large 14 dollar savings for customers. 15 I have listed in the submissions the 16 projections by Enbridge Consumers Gas and Union Gas on 17 the life cycle savings to customers that will come from 18 their energy efficiency programs, and they total more 19 than $400 million in customers' pockets. 20 That doesn't even include the environmental 21 benefits from the reduced pollution between those gases 22 and other pollutants. 23 That savings on the gas side is just an 24 indicator about the potential on the electricity side 25 because it is, I think, generally accepted that the 26 savings from DSM would be even larger, potentially, on 27 the electricity side because electricity is more 28 expensive and consumes a larger share of the energy 63 POLLUTION PROBE, Presentation 1 dollar; and also because electricity tends to have 2 significantly more serious pollutant emissions because 3 of the use of coal-fired plants. 4 So to penalize MEUs for using energy 5 efficiency programs is cutting off consumers from 6 potentially hundreds of millions of dollars of financial 7 savings. 8 We mentioned in our previous submissions that 9 energy efficiency, in principle, clearly leads to 10 greater business efficiency in Ontario's industries and 11 as a result of that potentially creates jobs. 12 Again on the issue of public interest, as I 13 mentioned, in addition to the dollar savings there is a 14 substantial air pollution concern as has been mentioned 15 in a number of previous hearings. 16 The Ontario Medical Association last year 17 issued a report calling the pollution in the air in 18 Ontario a public health crisis, to use their words, and 19 identified in their view that there are a significant 20 numbers of deaths actually attributable to air pollution 21 in Ontario. I believe the annual figure they estimated 22 was in the area of 1,800. 23 I don't say that to be alarmist. I say that 24 to be factual and realistic. 25 The other factor in this air pollution 26 equation is that the Ontario Power Generation 27 Corporation is Ontario's largest corporate source of 28 many of the air pollution specifics, and therefore 64 POLLUTION PROBE, Presentation 1 energy efficiency incentives stand to create some real 2 benefits by reducing the pollutants that come from OPG's 3 coal-fired plants. 4 Finally in terms of the public interest it is 5 very important to keep in mind, in my submission, that 6 the Government of Ontario promised, when implementing 7 electricity competition, that it will "ensure that the 8 province's environmental protection record is maintained 9 and improved". 10 So to put in place a penalty for energy 11 efficiency not only runs counter to the objective in the 12 Act, it would appear to run counter to one of the 13 fundamental planks in the competition platform. 14 Fourth, the multi stakeholder implementation 15 task force established by the Board for advice on PBR 16 mechanisms for the MEUs recommended that the system to 17 be adopted by the Board should allow MEUs who wished to 18 use energy efficiency programs to apply for them, and 19 specifically to apply for lost revenue adjustment 20 mechanisms -- which are known as LRAMs -- or a demand 21 side management variance account or Z-factor, or to 22 apply for a shared savings mechanism, or SSM, as 23 mentioned earlier already in the gas context. 24 It is unfortunate that these recommendations 25 were not adopted by the Board staff in the proposal 26 before you. I submit that the present proposal is 27 inconsistent with the implementation task force. 28 Pollution Probe suggests that it is not that 65 POLLUTION PROBE, Presentation 1 difficult to correct this problem -- and I would call it 2 a serious problem. It can be corrected mainly by making 3 an amendment to the Handbook which would, as I said 4 earlier, allow and indeed encourage MEUs who wished to 5 promote energy efficiency to apply for one of the 6 regulatory mechanisms that are available to do so, 7 including the LRAM or a variance account or Z-factor, or 8 an SSM. 9 In doing so, they would be simply making use 10 of a mechanism already carefully thought out by the 11 Board in the context of several hearings on the gas side 12 and already being rolled out in that sector. So it is 13 not something novel or new. 14 In terms of the specifics of that, the second 15 Pollution Probe proposal would be that because MEUs may 16 not have time to develop some of these mechanisms before 17 the market is opened in 2000, they should be permitted 18 to apply for DSM incentives for the years 2001 or 2002 19 after the market is opened. 20 Third, in terms of correcting this mistake, 21 the OEB, in Pollution Probe's submission, could 22 establish a multi stakeholder task force or some other 23 proceeding to review how the second generation PBR 24 plans -- that is, after 2002 -- should motivate the MEUs 25 to promote wise and efficient use of electricity. 26 Those are Pollution Probe's submissions on the 27 major issues with respect to energy efficiency. I do 28 have a number of shorter comments on the other issue, 66 POLLUTION PROBE, Presentation 1 the second issue of rate design. 2 As you are aware, as part of the PBR proposal, 3 Board staff are proposing a substantial redesign of 4 distribution rates. The part that I would like to 5 highlight today is the proposal to reduce the energy 6 rates and demand rates and to increase very 7 substantially the fixed monthly customer charge. 8 In reducing the energy rates and the demand 9 rates and in increasing the fixed customer charge, the 10 Board's staff is motivated by an intent to recover the 11 MEUs' long-run marginal cost of distribution, and to do 12 so in their energy or demand charges, but to recover all 13 of the other residual costs in the fixed monthly 14 charges. 15 There are two major concerns from an 16 environmental point of view with this proposal, in 17 Pollution Probe's submission. 18 The one is that this proposal is based on a 19 misinterpretation of a rather old study, and that 20 factually it is more likely that the MEUs' real long-run 21 marginal costs of distribution are quite a bit larger 22 than the Board staff's proposed energy and demand 23 charges. 24 If I may refer on that factual point to 25 evidence of Paul Chernick submitted on behalf of the 26 Green Energy Coalition, he says in his submission 27 entitled "Designing the PBR System for Ontario Electric 28 Distribution Utilities to Facilitate Cost Effective DSM" 67 POLLUTION PROBE, Presentation 1 that: 2 "With the correction that I have 3 identified, that estimate goes from $3.7 4 per megawatt hour to over $14 per 5 megawatt hour." (As read) 6 I will stop the quote there. 7 With that kind of potential factual 8 difference, in Pollution Probe's submission it would be 9 premature to make such a substantial change. 10 The other concern Pollution Probe has with 11 that change is that it will reduce customers' incentive 12 financially to use electricity wisely and efficiently. 13 This is important because, as mentioned earlier, what we 14 are using in that context is coal-fired electricity that 15 has some very real air pollution effects. 16 That proposal by staff is also in conflict, in 17 our submission, with the Section 1 of the Act 18 requirement that the Board facilitate energy efficiency. 19 Pollution Probe's recommendation on that rate 20 design issue would be that the OEB should not approve a 21 significant increase until it has better factual 22 information on MEUs' long-run marginal cost and until 23 the Ministry of the Environment has established 24 emissions caps which will lead to an orderly phase-out 25 of coal-fired power presently generated by OPG. 26 In summary, Pollution Probe suggests that the 27 incentives that would result from the two -- on the two 28 issues I have identified from the present proposal are 68 POLLUTION PROBE, Presentation 1 quite serious, quite seriously problematic, from an 2 energy efficiency and environmental and, indeed, 3 financial point of view, that they are not that 4 difficult to correct, and that it would be much more 5 consistent with the Board's statutory mandate and with 6 some of the studies already in place, such as from the 7 implementation task force and from the very important 8 issues of public interest related to, potentially, 9 hundreds of millions of dollars of customer savings and, 10 of course, from the reality of air pollution that, we 11 submit, is at stake here. 12 Those would be our submissions. We would be 13 pleased to answer any questions if there are any. 14 Thank you, Mr. Chairman. 15 THE PRESIDING MEMBER: Thank you, 16 Mr. Klippenstein. 17 Do Board staff have any questions? 18 MS KWIK: Yes, I do, Mr. Chair. Thank you. 19 I just wanted to clarify -- actually, it's not 20 a question, just a clarification -- that Mr. Chernick, 21 in Mr. Chernick's evidence, Exhibit C, he points out 22 that line losses were not included in the calculations 23 provided in that exhibit. 24 In fact, the rate guidelines that Ontario 25 Hydro produced was specific that the number of .0062 26 cents does include line losses. 27 I just wanted to clarify that. 28 THE PRESIDING MEMBER: Any other questions, or 69 POLLUTION PROBE 1 clarification, Board staff? 2 Dr. Zerker? 3 MEMBER ZERKER: Thank you. 4 I wonder if you could help me. Bearing in 5 mind if we assume that the utility is strictly a 6 distribution agency, could you be specific about the 7 kind of DSM measures that would apply (microphone 8 interruption) strictly distribution agency? A little 9 more specifics. As I read some of your earlier 10 submissions, I didn't have any detail on that. Okay? 11 Bearing in mind what the law says about where 12 the activities would be in affiliates and where they 13 would be in the (microphone interruption). 14 MR. KLIPPENSTEIN: Mr. Gibbons will comment on 15 that -- and thank you for raising that because I note 16 that Toronto Hydro also raised a question, earlier, of 17 what an LDC's role should be in these programs. 18 MEMBER ZERKER: Right. That's what I would 19 like to hear. 20 MR. GIBBONS: Yes, it's correct that under the 21 world we are moving into, the municipal electric 22 utilities will, as regulated utilities, will simply be 23 distribution utilities. 24 But, nevertheless, they can play a leadership 25 role in energy efficiency programs that not only would 26 use distribution costs and would use the need for new 27 distribution infrastructure but also can provide savings 28 in terms of the commodity and also lead to reduced 70 POLLUTION PROBE 1 pollution. 2 So, even though they are just a distribution 3 utility, their DSM programs can, and should, take into 4 account the total benefits of reducing electricity 5 consumption and the total benefits in terms of reducing 6 customers' bills -- and that's what we have on the gas 7 side. 8 The gas utilities, like Enbridge Consumers 9 Gas, are analogous, in terms of their regulated 10 component. They are just pipes companies or 11 distribution companies. 12 But Enbridge Consumers Gas and Union Gas, when 13 they evaluate their energy efficiency programs, they 14 don't look at the benefits just in terms of reduced 15 expenditures on pipe infrastructure but, also, the 16 benefits in terms of reduced gas commodity costs and 17 reduced environmental and public health costs. 18 So it is important to take the big picture. 19 I think the new emphasis, now, with the 20 removing of the ancillary services from the utilities' 21 businesses, is that utilities will achieve these energy 22 efficiency benefits by working with channel partners to 23 transform the market to get more energy-efficient 24 technologies in the marketplace and adopted by 25 customers. 26 So it's not as if Toronto Hydro or Enbridge 27 Consumers Gas would actually come into your home and do 28 the retrofit, or the sealing of the doors, or come into 71 POLLUTION PROBE 1 this building and actually be the energy service company 2 that actually achieves the actual -- or delivers the 3 actual DSM savings, but they would partner with all 4 kinds of channel partners and help those partners be 5 more effective in delivering DSM and promoting energy 6 efficiency. 7 You know, for example, Enbridge Consumers Gas 8 is working with the City of Toronto's Better Buildings 9 Partnership, which is working to reduce the energy bills 10 of buildings like this building in the City of Toronto. 11 They can be partnering with water heater 12 manufacturers, or Environment Canada's "ecolevel 13 program", to ensure that the most efficient water 14 heaters are rented, or sold, in the new deregulated 15 energy market. 16 Does that help? 17 MEMBER ZERKER: It helps some. Just some. 18 But let me ask you, then, going on from where 19 you are: If, in fact, as you suggest, the utility can 20 reduce its own costs, by virtue of some of these 21 programs that are available, and if the general 22 inflation factor, IPI, is higher, then why would there 23 not, even under a price cap scheme, why would there not 24 be an incentive on the part of the utility to go into 25 those kinds of programs? 26 MR. GIBBONS: Well, under price cap 27 regulation, there will be -- in certain specific 28 situations, there will be an incentive for the utilities 72 POLLUTION PROBE 1 to DSM. Or there could be. 2 For example, in areas where they are 3 capacity-constrained and they might need new 4 distribution lines or new transformer stations, it might 5 very well be in their economic self-interest to do DSM. 6 But we believe that there will be many, many 7 instances where it will not be in their financial 8 self-interest to do DSM. 9 For example, in most of the areas of Toronto, 10 or most areas of a municipal electric utility's 11 distribution system, it is not capacity-constrained and, 12 therefore, when you are not capacity constrained, in the 13 short run, your marginal costs of delivering an extra 14 kilowatt of electricity is effectively zero. And so, if 15 you do DSM, you lose that sale, you lose the marginal 16 revenue, so your revenues go down when you do DSM. 17 If you are not capacity-constrained, your 18 costs don't go down. So, the net result is a reduction 19 in your profit. And that, I think, is definitely the 20 way that most municipal utilities' staff perceive 21 them -- the situation they perceive themselves to be in 22 most of the time. In the short run, if they do DSM, 23 typically, it will reduce their profits. 24 So there can be special cases. But, as a 25 general rule, the price cap regime will, more often than 26 not, penalize them from doing DSM. 27 MEMBER ZERKER: Do you know that the price cap 28 regime is the introductory stage for the PBR and that 73 POLLUTION PROBE 1 the objective is to go to a yardstick regime? 2 Would you hold that the yardstick approach has 3 as onerous a profile as the one that we are talking 4 about now, which is the price cap? 5 Would you be more satisfied that there's room 6 for efficiencies within a yardstick approach? Or are 7 you still as concerned about the second generation? 8 MR. GIBBONS: Well, I'm not quite sure just 9 how yardstick regulation will be implemented by the 10 Ontario Energy Board, so I can't, quite frankly, comment 11 on how good or bad that may be, from a DSM point of 12 view. 13 But I guess what we were most concerned is we 14 are dealing, right now, with the first generation -- 15 which is the price cap proposal -- and we are not 16 saying, "Don't do price cap", we are just saying, "If 17 you bring in price cap, please modify it so that 18 municipal electric utilities that want to promote energy 19 efficiency can apply for additional incentives so they 20 won't be financially penalized from doing that and they 21 will be financially rewarded". 22 MEMBER ZERKER: I take your point there. 23 But, then, I would ask you: If, as you 24 suggest, the economics are as they are, why would any 25 utility be interested in adopting it, other than from a 26 social welfare point of view? 27 MR. GIBBONS: Well, if it -- 28 MEMBER ZERKER: I mean what I'm asking you is: 74 POLLUTION PROBE 1 Where are the economic incentives for a utility to do 2 that? 3 MR. GIBBONS: You see, that's our problem. 4 Under price cap regulation typically there aren't the 5 right economic incentives for them to reduce it. But if 6 the price cap is modified with our three suggestions, 7 the lost revenue adjustment mechanism, a demand side 8 management variance account or Z-factor and a share 9 savings mechanism, then there will be the economic 10 incentives for them to do it, and we believe they will 11 then do it aggressively. 12 If I can just turn you back to the -- 13 MEMBER ZERKER: I just wanted to clarify. 14 So you are suggesting that those measures be 15 introduced and that would create the incentive and 16 therefore the individual MEUs would have a reason for 17 choosing that? 18 MR. GIBBONS: Exactly. 19 MEMBER ZERKER: Okay. All right. 20 MR. KLIPPENSTEIN: I think if I can just add 21 to that, Dr. Zerker, you put your finger on it when you 22 asked a question about how these programs reduced the 23 costs of MEUs. The reality is -- and this is a key 24 distinction -- they don't. They increase the cost for 25 the consumers -- they reduce the costs for the 26 consumers -- 27 MEMBER ZERKER: You are saying reduce the 28 costs? 75 POLLUTION PROBE 1 MR. KLIPPENSTEIN: They reduce the costs for 2 the consumers but they actually increase the costs for 3 the MEUs. That is why, as you identified, the MEUs may 4 not have an incentive to do this even though it is 5 financially beneficial to the consumers. 6 This state of affairs exists because of what 7 you could call market failures. There are certain 8 situations where what makes financial sense to the 9 customer will not be adopted by them without a little 10 help or nudge in terms of, for example, the information 11 that is available to them. 12 MEMBER ZERKER: Let me just clarify: So the 13 price cap modified is something that you would find 14 reasonable, a reasonable approach. The price cap as is 15 is the one that you are objecting to. 16 So it isn't that you are saying to the Board 17 that you want us to throw out the baby with the bath 18 water, that you want us to warm up the bath water, is 19 that it? 20 MR. KLIPPENSTEIN: Yes. We would advocate, 21 yes, warming up the bath water and giving the baby a 22 nice warm bottle as well. 23 MEMBER ZERKER: For now those are my 24 questions. 25 THE PRESIDING MEMBER: Thank you, Dr. Zerker. 26 Mr. Vlahos. 27 MEMBER VLAHOS: Thank you. 28 Gentlemen, just a couple of questions on the 76 POLLUTION PROBE 1 first issue and a couple on the second. 2 The first issue, of course, is the 3 conservation aspect of it. 4 There was some criticism, I understand, in the 5 Technical Conference about the piecemeal approach that 6 Pollution Probe is advocating in that utilities will be 7 coming in on their own to seek DSM programs to be 8 approved. The criticism has been, as I understand, why 9 don't we do it for all at once as opposed to a piecemeal 10 approach which may get you into a different position for 11 a utility depending on when and who is hearing the case. 12 What is your reaction to that? 13 MR. KLIPPENSTEIN: That is an important 14 practical issue and we recognize that. 15 In my submission, I think our view is that it 16 is not likely to be in practice as big a problem as it 17 could be in theory. I think that because of the number 18 of changes going on that it is not likely that all MEUs 19 will sort of rush in immediately and adopt a wide 20 variety of proposals that they have constructed. 21 I suspect that in reality what is likely to 22 happen is a certain high degree of conformity, both in 23 the proposals and probably a degree of leadership in 24 which MEUs come forward first so that there won't be the 25 kind of fragmentation and disjointedness which 26 theoretically could happen. 27 You know, there has been already a great deal 28 of effort on the gas side gone into the SSMs, the LRAMs, 77 POLLUTION PROBE 1 it is not in people's interests to reinvent the wheel 2 every time. 3 So I think that practically speaking it is 4 really not likely to be that much of a problem. 5 I think that it may be that there is a role 6 for a more unified approach, as Pollution Probe 7 suggested, through a multi-stakeholder task force that 8 could work on the second generation plans and bring a 9 larger degree of uniformity and co-ordination to those. 10 That would be a second reason I think that it would not 11 be disruptive or fragmented over the longer term to put 12 this in place. 13 Mr. Gibbons may have something to add to that. 14 MR. GIBBONS: Mr. Vlahos, if I could just make 15 a few extra points. 16 Pollution Probe has no problem if the Board 17 wants to have some kind of generic proceeding to deal 18 with this on a more comprehensive and integrated basis. 19 We have no problem with that. 20 I guess the point we want to make is, in the 21 interim, before you had that generic hearing and got 22 your result, in the interim you certainly should not be 23 penalizing the municipal electric utilities that want to 24 do energy efficiency, given that now energy efficiency 25 is part of the Ontario Energy Board's mandate and its 26 Act, given that some municipal electric utilities 27 already have DSM programs. 28 For example, Toronto Hydro is a member of the 78 POLLUTION PROBE 1 Save Toronto's Better Buildings Partnership, which is a 2 very important DSM initiative. Toronto Hydro is owned 3 by the City of Toronto, the City of Toronto has very 4 ambitious environmental and public health goals which 5 they want to see accomplished, and I think therefore it 6 would be wrong for the OEB to go and penalize Toronto 7 Hydro, which is owned by the City of Toronto, from 8 undertaking activities that are in the public interest 9 and the shareholder wants to see accomplished. 10 Again, the problem with the generic 11 proceedings, they are fine but they often take a long 12 time and there can be a huge lost opportunity before we 13 get the result. 14 If I can just go back to the situation of gas 15 IRP and DSM, I believe it was in December 1989 that the 16 Board handed down their E.B.R.O. 462 Union Gas case 17 which said that there should be a generic hearing for 18 gas DSM. So that was December 1989. It wasn't until 19 the summer of 1993 that the Board actually issued its 20 gas DSM report, E.B.R.O. 169-3, and it wasn't until a 21 further year, until the fall of 1994, that the first DSM 22 programs actually were introduced into the marketplace 23 by the Consumers Gas Company. So that was about a five 24 year lag. 25 I would suggest to you now, with air pollution 26 being a public health crisis, with our very ambitious 27 Kyoto commitments, we can't afford to wait five years. 28 If there are some municipal electric utilities that are 79 POLLUTION PROBE 1 willing to do energy efficiency programs now to reduce 2 their customers bills, we shouldn't stand in their way. 3 MEMBER VLAHOS: You don't feel that we know a 4 bit more about DSM today than we did 10 years ago, 5 Mr. Gibbons -- 6 MR. GIBBONS: Oh, absolutely. 7 MEMBER VLAHOS: -- and therefore it may not 8 take five years. 9 MR. GIBBONS: I hope not. 10 MEMBER VLAHOS: Just to carry this, then, to a 11 higher level, and that is: We spoke about generic in 12 terms of all the electrical utilities, and I guess one 13 could extend that to why not bring the gas utilities as 14 well because, you know, we also look at PBR in a 15 comprehensive way for gas, we only have a limited O&M 16 PBR in one of the utilities. But even higher than that, 17 being that distribution is only, I understand, what, 18 10-15 cents out of the dollar, of the power dollar in 19 the province, why not bring all the other sectors in so 20 that brings it to a higher level. 21 So what would be your response to that? 22 MR. GIBBONS: Well, certainly, I mean, if the 23 Ontario Energy Board wants to, I mean, it's certainly 24 within your mandate, you could bring in all the 25 electricity marketers. 26 MEMBER VLAHOS: That wasn't my question, 27 Mr. Gibbons. 28 Do we have the authority to do that? Do we 80 POLLUTION PROBE 1 have the authority to bring in the marketers and the 2 producers? 3 MR. GIBBONS: Well, I don't know, but -- I 4 just don't know, I'm not a lawyer. 5 But even if you had the authority, that would 6 be sort of unprecedented. I don't know of a regulatory 7 commission that tries to require -- to regulate the DSM 8 activities of marketers. I mean, the whole purpose of 9 deregulation was to have less regulation for that 10 element of the electricity business. 11 But the Act clearly envisions that the Board 12 will continue to regulate the natural monopoly elements, 13 the distribution and the transmission companies, and I 14 believe it makes a lot of sense for those utilities to 15 play a leadership role in delivering DSM in Ontario. 16 Even though they may only be 10 or 15 cents of 17 the energy dollar, they can still leverage much bigger 18 savings and I believe that's appropriate in my opinion 19 and I also believe it's what the Act and the government 20 intends. 21 MEMBER VLAHOS: Thank you, Mr. Gibbons. 22 Just before I leave DSMA, based on Miss Kwik's 23 comment or clarification, I wasn't sure whether the $14 24 per megawatt hour for Mr. Chernick's evidence should be 25 higher or lower? Do you understand what my question is? 26 You clarified that latters were included or excluded, I 27 wasn't sure. 28 All I want to know is when the comparison is 81 POLLUTION PROBE 1 made on page 7 of the Pollution Probe submission, $3.7 2 per megawatt hour to over $14, how did the numbers 3 change, in which direction? 4 MR. GIBBONS: It will go down from the $14. 5 MEMBER VLAHOS: It will go down from the $14. 6 MR. GIBBONS: But according to Mr. Chernick 7 there were other problems too, not only the losses 8 problems, but the lack of an inflation escalation and 9 also the lack of including of overhead costs I believe. 10 MEMBER VLAHOS: Okay. But on that point alone 11 though -- 12 MR. GIBBONS: It goes down. 13 MEMBER VLAHOS: -- the $14 goes down. 14 Thank you. 15 Mr. Gibbons, another question for you. We are 16 talking about -- basically, what you are talking about 17 is the price elasticity of demand. I guess you and I 18 have been around for some time, at least on the gas 19 side, and we know that there is no such conclusive 20 study, so help me, you have been with electricity longer 21 than I have and even more recently. Has there been such 22 a study that you are aware of because I am not -- 23 MR. GIBBONS: I am not aware of any conclusive 24 study. I think we can all agree that if the price goes 25 down consumption will go up and how responsive it is I 26 can't tell you. I think it will be more responsive in 27 the long run than the short run. I think we can all 28 agree on that, but just by how much I couldn't tell you. 82 POLLUTION PROBE 1 MEMBER VLAHOS: So there hasn't really been 2 anything comprehensive that you know of that you want to 3 advise the panel? 4 MR. GIBBONS: What I am aware of, whenever I 5 see studies on elasticity there is a plethora of 6 studies. They don't all come to the same results. I 7 don't think that there is any one number that we can say 8 is the right one or the number. 9 MEMBER VLAHOS: Thank you. 10 My last question, on page 8 of the submission 11 you are asking the Board not to approve a significant 12 increase in the MEUs customer charges until, and it goes 13 on. Is there a specific level in Pollution Probe's mind 14 as to what should be that level of increase? 15 MR. GIBBONS: No, we don't. But my belief is 16 that the Board staff's proposal is nothing but a very 17 large increase. For example, in the past I think the 18 customer charges were much lower than what we are 19 talking about now and so we are talking about a very 20 large increase. 21 If it was say 5 per cent or 10 per cent that 22 would be I think insignificant compared to what Board 23 staff is proposing. 24 MEMBER VLAHOS: Would that be a full audit or 25 once you decided as to what the IDC ought to be as 26 opposed to what the proposal is, then you back it up to 27 the administration charges. Is that how you say it? 28 MR. GIBBONS: I think at the minimum we have 83 POLLUTION PROBE 1 to be sure that we have got the IDC number correct. We 2 interpreted Mr. Chernick's testimony, there was good 3 reason to think that the IDC number was far from being 4 correct or far from being actually competent was 5 correct, so that was the first thing. We have to get 6 the good information before making such a radical 7 change. 8 Then after we get better information, you 9 still might not want to recover all the residual costs 10 then in the customer charge if you wanted to promote 11 energy efficiency or energy conservation because the 12 more amount of money you put in the fixed customer 13 charge, the less financial incentive there is for the 14 customer to conserve electricity. 15 So that there are those two issues: One, 16 trying to get the rates cost related and that's one 17 legitimate objective. There is another objective of 18 trying to incent the customer to conserve energy and 19 those two objectives can sometimes conflict. 20 Now, once we know what the true IDC number is 21 we will know the extent to whether they conflict. Maybe 22 they don't. If Mr. Chernick's analysis is right there 23 isn't a conflict, but I guess if Board's staff number 24 they propose is correct then there is a conflict. 25 MEMBER VLAHOS: I understand the direction, 26 but let's play with the number. Say $14 was the number. 27 MR. GIBBONS: Yes. 28 MEMBER VLAHOS: Then what is the premium that 84 POLLUTION PROBE 1 this panel ought to attach to that $14 number before it 2 is able to calculate the residual amount that should be 3 recovered through the customer charge? 4 MR. GIBBONS: I think it was Mr. Chernick's 5 testimony, if you use the $14 the IDC charges will cover 6 it in the energy charge, then for residential customers 7 there would be no residual to recover in the customer 8 charge. 9 MEMBER VLAHOS: I see. So it would be totally 10 recovered in the energy charge? 11 MR. GIBBONS: Yes, that's my understanding of 12 his analysis. Whereas for small commercial customers 13 there will be a bit to recover in the customer charge. 14 MEMBER VLAHOS: Mr. Dominy reminds me how does 15 that qualify under the description of income rental if 16 it covers the whole? 17 MR. GIBBONS: Again, there can be a difference 18 between incremental costs and average costs. 19 MEMBER VLAHOS: Thank you. 20 Those are my questions. 21 Thank you, Mr. Chairman. 22 THE PRESIDING MEMBER: I wanted a very quick 23 question of understanding myself and that is, basically, 24 you talk about the penalties in the PBR system to the 25 use of DSM. I was wondering if you would elaborate how 26 much more there are penalties in the PBR system than 27 exist in rate regulation? Even if it was cost of 28 service regulation, the utilities still faces the same 85 POLLUTION PROBE 1 concerns about loss of sales. 2 MR. GIBBONS: Yes, that's true, Mr. Dominy, 3 and that's why on the gas side where we have had those 4 traditional cost of service regulations and there has 5 been those penalties, that's why Pollution Probe has for 6 many years advocated these type of extra DSM incentive 7 mechanisms should be put in place to remove the existing 8 disincentive and to create actual positive incentives. 9 THE PRESIDING MEMBER: Basically, what you are 10 saying is PBR is here, DSM incentives is here and you 11 want to continue DSM incentives regardless of what the 12 rate-setting mechanism was? 13 MR. GIBBONS: Again, yes, basically. If there 14 was a price cap rate setting PBR scheme, for example, is 15 more adverse to DSM than say a revenue cap. So if you 16 go for a price cap you are making a decision and that 17 means it is even more of a rationale for these special 18 DSM type incentives. 19 THE PRESIDING MEMBER: Is it worse than cost 20 of service regulation? 21 MR. GIBBONS: It is worse than cost of service 22 regulation in the sense that you are talking about 23 regulation for a three year time period, as opposed to 24 cost of service which can be a one year time period. So 25 when you do a DSM incentive under a three year time 26 period, the lost revenue is not just for one year, but 27 it's for three years, so the penalty can be greater. 28 THE PRESIDING MEMBER: So if the cost of 86 POLLUTION PROBE 1 service were extended by only having a rate application 2 every three years it would be equivalent? 3 MR. GIBBONS: Yes. 4 MR. KLIPPENSTEIN: On that point, Mr. Chair, I 5 could add that we understand the legislation in 6 describing the objective of the Board when the 7 legislation uses the word "to facilitate energy 8 efficiency," that it's an active requirement or 9 objective and not a static one. 10 So that it's something that the statute 11 mandates the Board to actively pursue. So it is useful. 12 It is an ongoing issue, an ongoing objective and so that 13 while at this point while we are examining a price cap 14 regulation, it's particularly a good time to look at the 15 energy efficiency issue. The Board is requested under 16 the statute to actively facilitate it and so a step 17 forward is part of the mandate or task that the Board is 18 entrusted with. 19 THE PRESIDING MEMBER: Thank you, Mr. 20 Klippenstein and Mr. Gibbons. Thank you for your 21 presentation and it is helpful to the Board. Thank you. 22 I know there is a next panel up and we are 23 running a bit behind, but I think we have been sitting 24 now for two and a half hours, so it might be useful to 25 have a 10-minute break. Do you agree? A 15-minute 26 break. I apologize to the next presenter. We will be 27 starting you somewhat late, but we will start in 28 15-minutes time. Thank you. 87 POLLUTION PROBE 1 --- Upon recessing at 1129 2 --- Upon resuming at 1148 3 THE PRESIDING MEMBER: I'm told that we are 4 not coming across the microphones as clearly as we 5 should be, and I think that is some advice to everybody. 6 Please try and speak close to the microphone if you can. 7 I think the problem has been ourselves rather than the 8 witnesses, but I raise it to everyone. 9 Thank you. 10 So now we have the Coalition of PUCs. I 11 believe, Mr. Mia, you will introduce them. 12 Thank you. 13 PRESENTATION 14 MR. MIA: Good morning. 15 Members of the Board, my name is Ziyaad Mia 16 and I'm counsel for the Coalition of Distribution 17 Utilities. Appearing with me today to assist are: from 18 the far left, Mr. David Frey, Director of Finance with 19 Brampton Hydro; Mr. Brian Wilkie, General Manager for 20 Niagara Falls Hydro; Mr. Neil Sanford, Managing Director 21 for Oakville Hydro; and, on my right, Mr. Jim MacKenzie, 22 General Manager for Guelph Hydro. 23 The Coalition of Distribution Utilities 24 include Brampton Hydro, Bracebridge Hydro, Cambridge and 25 North Dumfries Hydro, Guelph Hydro, Niagara Falls Hydro, 26 Oakville Hydro, Pickering Hydro, Richmond Hill Hydro and 27 Waterloo North Hydro. 28 I appear before you today to deliver our 88 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 submission on behalf of the Coalition with respect to 2 the Ontario Energy Board staff's proposed Performance 3 Based Regulation Rate Handbook for Electricity 4 Distributors. 5 The Coalition represents a diverse range of 6 electricity distributors. Naturally, with such a 7 diverse range of numbers, there is also diversity of 8 opinion, outlook and interests. 9 We believe that the concerns we have raised in 10 our previous submissions filed with the Board, and which 11 will be highlighted here today, reflect not only the 12 views of any one distributor but rather a broader 13 consensus of opinion that arguably many distributors 14 would support. 15 We would like to begin by expressing our 16 support and appreciation to Board staff and their 17 consultants in the development of the draft Performance 18 Based Regulation Handbook. Given the tight time frame 19 within which this significant task was undertaken, the 20 end product that we have is quite good. 21 As the new electricity market evolves, it is 22 clear that incentive-based regulation is the most 23 effective way to achieve efficiencies and transfer those 24 savings to customers and shareholders. In this regard, 25 the Coalition of Distribution Utilities supports the 26 Board's efforts in developing an incentive-based 27 regulation system for electricity distributors in 28 Ontario. 89 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 Electricity sector restructuring is new not 2 only to Ontario but to many jurisdictions around the 3 world. As such, we recommend prudence and caution in 4 approaching this immense task, including the design of a 5 performance-based regulation regime. We believe that 6 getting this first generation PBR right is very 7 important because the consequences of getting it wrong 8 are potentially long lasting due to various factors, 9 including, among others, regulatory, economic and 10 systemic inertia. 11 Another consequence of getting this first step 12 wrong is the danger of eroding support for PBR as a 13 regulatory mechanism itself and damaging confidence in a 14 nascent market. 15 One of the principles of the new market is 16 fairness: fairness for market participants, fairness in 17 transactions, and fairness in the application of the 18 market's rules and regulation. As such, any 19 incentive-based regulation scheme should also be fair. 20 We also reiterate the goals outlined in the 21 PBR Handbook as to its purpose, namely: to minimize the 22 potential for bad outcomes, to achieve light-handed 23 regulation, and to establish a basis for future PBR 24 regimes. 25 Again, we restate our support of the Board 26 staff's and their consultants' efforts in developing the 27 PBR Handbook. Our specific comments follow and are 28 intended to suggest improvements and changes to the PBR 90 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 Handbook that will further the explicit and implicit 2 goals underlying incentive-based regulation,and results 3 in a more effective and accurate incentive-based 4 mechanism. 5 With respect to rate adjustments, as a point 6 of clarification, we ask the Board to outline the rate 7 adjustment mechanism where a distributor chooses to earn 8 a return which is lower than the prescribed maximum. 9 A distributor may wish to earn a lower than 10 maximum return in any one year for a variety of social, 11 economic or business reasons. Our concern is that a 12 distributor that chooses a lower return is not penalized 13 for doing so. 14 In effect, the PBR rate adjustment mechanism 15 should allow flexibility without penalizing those 16 distributors that select a lower-than-maximum return in 17 any one rate period. We recommend a mechanism that 18 would allow such deferred returns to be recovered in 19 later periods. 20 As discussion and debate at the PBR technical 21 conference and elsewhere has attested, contributed 22 capital is, euphemistically, an open and live topic in 23 the development of the new market. 24 We acknowledge the draft PBR Handbook's view 25 on future contributed capital. However, the Ministry of 26 Energy, Science and Technology and the Board should 27 appreciate the huge impact this change will have on 28 existing ratepayers in growth communities when a 91 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 business decision is made to no longer collect 2 contributed capital, thereby effectively abandoning the 3 principle of growth paying for itself. 4 Furthermore, it is our understanding that 5 maintenance and repair costs for future contributed 6 capital assets will be recovered from incentive-based 7 rates. Excluding such costs from incentive-based rates 8 would be unfair and would penalize distributors for 9 investing in system maintenance and reliability 10 enhancement. Such a result is contrary to the 11 fundamental notions underlying incentive-based 12 regulation and the objectives of the Board as outlined 13 in the Ontario Energy Board Act. 14 With respect to past contributed capital, our 15 position differs from that outlined in the PBR Handbook. 16 Consistent with our supplementary submission, filed with 17 the Board on September 14th, 1999, we recommend that 18 past contributed capital be allowed to receive a 19 market-based rate of return equal to that received by 20 all other capital utilized by a distribution 21 organization. 22 Our recommendation is founded on several 23 factors, including the following: 24 Essentially, all capital investments in 25 Ontario's electricity distribution systems were paid for 26 by customers and, as such, all capital is effectively 27 contributed capital. 28 The exclusion of past contributed capital from 92 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 the market-based rate of return will influence the value 2 of distribution systems and this will ultimately have 3 detrimental economic and efficiency consequences. For 4 example, the value of a distribution system may have a 5 direct impact on the availability and cost of capital, 6 and this will in turn influence the economic efficiency 7 of the distribution business itself. 8 The exclusion of past contributed capital from 9 the market-based rate of return penalizes some market 10 participants for decisions made under the former 11 regulatory regime and which were motivated by 12 non-commercial considerations. 13 Lastly, the exclusion of past contributed 14 capital from receiving a market-based rate of return may 15 have unjustified discriminatory price impacts. 16 The ultimate consequence of the PBR Handbook's 17 approach to past contributed capital will be a 18 distortion of fairness in the dynamics and operation of 19 the market. 20 We submit that one of the objects of a truly 21 competitive market is to treat customers in a similar 22 manner with respect to prices, goods and services. As 23 such, any distinction that is not justified by the 24 market is artificial and serves only to distort the 25 efficient operation and competitiveness of the market. 26 The distinction of past contributed capital in 27 the PBR Rate Handbook introduces an irrelevant factor 28 into the market and thereby results in a distinction 93 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 being made between customers based only on the fact that 2 their respective distributors' capital structure is 3 differently constituted. 4 As a further incentive for realizing greater 5 efficiencies, we submit that the maximum limit on return 6 and equity be seen not as a cap but rather as a 7 threshold beyond which further gains would be shared 8 between distributors and customers. 9 Relative to the maximum-return-on-equity 10 concept outlined in the PBR Handbook, a sharing 11 mechanism would more accurately reflect competitive 12 forces and reward efficiencies more appropriately. 13 Whereas a maximum cap only encourages a 14 distributor to strive for gains up to the cap and no 15 further, a sharing mechanism would incent greater 16 efficiencies without introducing artificial 17 disincentives. 18 We submit that a threshold and sharing 19 mechanism would serve us better in attaining a truer 20 incentive-based mechanism which more effectively mimics 21 market forces. This would encourage greater 22 efficiencies while minimizing negative economic impacts 23 on customers and mitigating the potential for bad 24 outcomes. 25 Another area of concern for the Coalition is 26 the productivity factor. We are concerned that if a 27 crucial element of the PBR mechanism such as this is set 28 incorrectly, the implications on the entire scheme could 94 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 be significant. 2 As with the other components of the PBR 3 mechanism, we emphasize that it is crucial to be 4 accurate. There was much discussion and debate at the 5 technical conference regarding the magnitude of the 6 productivity factor and how it was to be determined. In 7 our concerns we do not pretend to pose alternative 8 methods or approaches for the determination of the 9 productivity factor. 10 However, we do suggest that the Board take a 11 cautious approach when examining and finally 12 establishing the productivity factor. In this regard, 13 we would highlight the following. 14 Since all costs that distributors face are not 15 controllable, significantly higher productivity gains 16 and controllable costs would have to be achieved to 17 attain the stated levels of productivity with respect to 18 overall costs. 19 For example, up to two-thirds of a 20 distributor's costs could be related to items such as 21 interest accrued, depreciation, corporate taxes and 22 dividends, with only one-third tied to items such as 23 maintenance, retail settlement and billing. 24 Therefore, achieving an overall productivity 25 improvement of 1.25 per cent may require a reduction of 26 3 to 4 per cent in those items which in fact can be 27 changed. 28 Second, scrutiny should be focused not only on 95 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 the particular data set used to derive productivity 2 targets but also on external economic and other factors 3 which may have influenced the data during the sampling 4 time frame, such as the impact of economic cycles, 5 policies and programs which may result, for example, in 6 periods of unusually high growth and expansion. 7 Finally, the potential that relatively high 8 productivity targets may disproportionately reward less 9 efficient distributors by giving them more room to move 10 in terms of achieving new efficiencies. Conversely, 11 high productivity targets may penalize those 12 distributors who have historically performed at high 13 levels of efficiency. 14 Without doubt, members of the Coalition have 15 historically been committed to high standards of service 16 to their customers. This commitment will be 17 strengthened in the new market as we believe that 18 service will be a central component of success in that 19 market. 20 Given this, we support the intent of the 21 Handbook in attempting to ensure that service is not 22 sacrificed in the pursuit of greater efficiency gains. 23 We are encouraged to see that quality of service is a 24 factor that will ultimately be used to assess 25 performance. 26 However, given our commitment to service, we 27 are concerned that a rigid reading and application of 28 the service quality standards, as outlined in the Draft 96 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 Handbook, may lead to unintended and possibly 2 counterproductive or bad outcomes. 3 Rather than counting telephone rings and using 4 stop watches to measure service quality, we would 5 support the development of a wider approach which would 6 more accurately measure customer satisfaction with the 7 quality of service provided. 8 We are not unaware of the difficulties that 9 are involved in accurately and effectively measuring and 10 monitoring service quality. However, we submit that if 11 service quality is eventually to be a criterion in 12 incentive based regulation, it is imperative at the 13 outset to develop an accurate, realistic and practical 14 model that will truly measure customer satisfaction with 15 service. 16 In this regard, we would suggest that the 17 Board possibly develop a standard form survey to gauge 18 and track customer satisfaction with service. 19 As the municipalities undertake the 20 restructuring of their electric utilities, they face 21 many choices. One of these choices involves the 22 transfer of street lighting assets from the municipal 23 owner to the new distribution company. 24 The Electricity Act authorizes the transfer of 25 assets through which the Municipal Corporation 26 distributes electricity to a distribution company. A 27 plain reading of the legislation suggests that all 28 distribution related assets may be transferred through 97 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 such a transaction. 2 Looking further, both the Ontario Energy Board 3 Act and the Electricity Act define "distribute" as the 4 conveyance of "electricity at voltages of 50 kilovolts 5 or less". 6 As such, we submit that street lighting assets 7 may fall within the definition of distribution assets as 8 defined in both those Acts. Furthermore, our 9 understanding in this matter is supported by the 10 inclusion of expenses for maintenance of street lighting 11 systems as distribution expenses in Appendix B of the 12 Draft Handbook. 13 Despite the foregoing, we are concerned that 14 there may be a lack of clarity with respect to the 15 nature of street lighting assets and their 16 transferability pursuant to transfer by-law. 17 As such, we request the Board to clarify the 18 foregoing issues in the interests of certainty and to 19 facilitate the restructuring activities of Ontario's 20 electric utilities. 21 More specifically, we seek clarification from 22 the Board with respect to, first, the demarcation of 23 street lighting assets between wires and fixtures; and 24 secondly, the unbundling of street lighting commodity 25 charges from the street lighting distribution and 26 maintenance charges. 27 Assistance from the Board with the foregoing 28 matters will assist distributors in establishing the 98 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 base for initial rates. 2 In conclusion, we express our appreciation for 3 the significant efforts of Board staff and their 4 consultants in developing the PBR Handbook. We also 5 reiterate our support for the notion of, and the 6 development of, an incentive-based system to regulate 7 distribution rates in Ontario. 8 However, we would like to state that it is 9 likely that electricity prices in Ontario will rise. As 10 such, the development of regulatory mechanisms and 11 benchmarks for Ontario's new electricity market must be 12 undertaken with a full appreciation of this overarching 13 reality. 14 Our concerns, as outlined in our previous 15 written submissions to the Board and in this submission 16 today, are focused on suggesting improvements to the 17 Handbook that would make it more reflective of market 18 forces, while keeping in mind the goal of minimizing bad 19 outcomes. 20 As stated at the outset of this submission, it 21 is crucial to get the first generation of PBR right. In 22 our written submissions to the Board and in this 23 submission today, we have highlighted the salient issues 24 that require additional attention and scrutiny by the 25 Board. 26 With respect to contributed capital, we 27 reiterate that the volume of debate and concern 28 surrounding the issue is evidence that the Board should 99 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 revisit the treatment of contributed capital in the 2 Draft Handbook. Our position is clear: past 3 contributed capital should, for the reasons outlined in 4 this submission today, and in our previous written 5 submission, receive a market-based rate of return equal 6 to that received by all other capital used by a 7 distributor. 8 Similarly, we respectfully submit that the 9 Board replace the concept of a cap on return on equity 10 with the mechanism that would share higher efficiency 11 gains between customers and their distributors. Such an 12 approach would encourage greater efficiencies while 13 minimizing the potential for adverse consequences on 14 customers. 15 Consistent with our focus on getting the first 16 step right, we repeat our concern that key criteria, 17 such as the productivity factor, be established in a 18 prudent manner. This means having regard to the 19 circumstances and conditions, both internal and 20 external, which influence a distributor's performance. 21 The adverse consequences of getting the fundamentals 22 wrong are significant, not only for distributors but 23 ultimately for the evolution of a healthy and 24 competitive market -- a bad outcome indeed. 25 Furthermore, our submission raised issues that 26 we require confirmation and clarification on: namely, 27 the ability to recover deferred returns from rate 28 periods where a distributor chose to earn a lower rate 100 COALITION FOR DISTRIBUTION UTILITIES, Presentation 1 of return than the prescribed maximum; our understanding 2 that the maintenance and repair costs expended on future 3 contributed capital can be recovered from 4 incentive-based rates; and the classification of street 5 lighting assets as distribution assets. 6 In terms of electricity sectors undergoing a 7 revolution, as with all revolutions there are sudden, 8 dramatic and enormous change that occurs within a very 9 short time. This sort of change brings with it the 10 potential for great progress and benefits. However, it 11 also brings the potential for serious harm. The trick, 12 of course, is to maximize the benefits and minimize the 13 harm. 14 In this regard, we would ask the Board to 15 assist us in making Ontario's electricity sector 16 revolution a positive experience for all in the new 17 market. 18 The PBR Handbook represents a new way of doing 19 business for Ontario's electricity distributors. The 20 Coalition of Distribution Utilities supports this change 21 and looks forward to participating in the new market. 22 We hope that our comments have been of 23 assistance. These are our submissions. Thank you. 24 THE PRESIDING MEMBER: Thank you very much, 25 Mr. Mia. 26 Does Board staff have any questions or 27 clarifications? 28 MS KWIK: Yes, I do, Mr. Chair; thank you. 101 COALITION FOR DISTRIBUTION UTILITIES 1 With reference to the street lighting, you 2 identify that you would like clarification from the 3 Board with respect to the unbundling of street lighting 4 commodity charges from the street lighting distribution 5 and maintenance charges. 6 In Appendix A of the Draft Rate Handbook, we 7 had included a methodology for unbundling street light 8 commodity from distribution charges. 9 Is this the point here, then, that there are 10 gaps in Appendix A that we need to address? 11 --- Pause 12 MR. MIA: We will look further at that and 13 sort of bring it up with other members of the Coalition. 14 MS KWIK: I would appreciate that. Thank you. 15 Another question I had was on the maintenance 16 and repairs costs for future contributed capital being 17 recovered through rates. You say here that this is your 18 understanding. 19 Are you saying that it was vague in the Draft 20 Rate Handbook whether this was, in fact, the case? 21 MR. MIA: I believe, for some of our members, 22 it wasn't entirely clear. 23 MS KWIK: It wasn't clear. Okay. So there's 24 need to make that explicit. Thank you. 25 That's all, Mr. Chair. 26 THE PRESIDING MEMBER: Mr. Vlahos? 27 MEMBER VLAHOS: Mr. Mia. 28 MR. MIA: Yes. 102 COALITION FOR DISTRIBUTION UTILITIES 1 MEMBER VLAHOS: So we have a record of the 2 response to Board staff on "Were there any gaps in 3 Appendix A with respect to the street lighting", could 4 you -- we should give it a number, Ms Kwik, so that we 5 can also follow that. 6 MS KWIK: Okay, Mr. Vlahos. 7 That would be Undertaking 1.2. 8 UNDERTAKING NO. 1.2: Coalition of PUCs 9 to ascertain if there were any gaps in 10 Appendix A with respect to the street 11 lighting 12 MEMBER VLAHOS: Panel, good morning, or 13 afternoon, rather. 14 I do have some questions, and anyone can 15 address those. 16 I will start with you, Mr. Mia. 17 Does your submission represent a complete list 18 of the Coalition's concerns? 19 MR. MIA: It represents, I think, a summary of 20 the highlights of our key concerns, but it should be 21 read, I think, in light of our original submission in 22 this matter and our supplementary submission -- and we 23 intend to make a final. 24 I believe some members, and maybe some of our 25 members here today may speak to the point of the time 26 frame, that they were concerned that there was a short 27 time frame in this whole process. 28 I don't mean to sort of bring that up at this 103 COALITION FOR DISTRIBUTION UTILITIES 1 stage, but there may be other issues which could be 2 raised in the final submission which may not have been 3 caught in the others. So, I would say: read as a 4 whole. 5 MEMBER VLAHOS: But from the issues that had 6 been thought of, is this an distillation, an adequate 7 distillation of what the concerns were? 8 MR. MIA: It's a distillation of the major -- 9 or our major concerns. 10 MEMBER VLAHOS: Where would we know the other 11 non-major concerns? 12 MR. MIA: We will raise sort of all the other 13 smaller concerns in the final submission. In addition 14 to these. 15 MEMBER VLAHOS: Is there something that we can 16 raise today so that we can all be helped as to what they 17 are? 18 --- Pause 19 THE PRESIDING MEMBER: Mr. Mia, I think what 20 Mr. Vlahos is asking is: In your two initial 21 submissions, there were quite a lot listed, more 22 detailed points you raised, and have any of those been 23 resolved through the technical conference? 24 MR. MIA: I won't be able to speak to the 25 exact point of whether they have been directly addressed 26 from the technical conference, but our position is that 27 this submission, today, represents our key concerns 28 where we would like some action from the Board and the 104 COALITION FOR DISTRIBUTION UTILITIES 1 questions we have raised for clarification. 2 The other matters, I would have to go back to 3 review the technical conference transcripts to see if 4 they have been directly addressed. 5 --- Pause 6 MR. VLAHOS: The reason I'm asking the 7 question is, to the extent there are any other live 8 issues, this is the forum where they should be brought 9 up and we can understand the nature of those issues and 10 ask some questions. 11 MR. MIA: Yes. 12 MEMBER VLAHOS: But we'll leave it at that. 13 Gentlemen, if I can take you to your comments 14 on the rate adjustments -- and that's on page 5 of your 15 prefiled material. I guess the statement that is made 16 there that a distributor can select a lower maximum 17 return. 18 And if you just turn over to page 6, the very 19 last line, there was a recognition that the utilities 20 may be motivated by non-commercial considerations. 21 I'm just trying to make those two jive, I 22 guess. Can somebody help me with that? 23 Is the assumption here that even if there is a 24 utility in private ownership, that there may be other 25 non-economic, non-profit maximization considerations 26 that may lead to lower rates? 27 MR. MIA: The other members of our Coalition 28 can jump in and clarify. 105 COALITION FOR DISTRIBUTION UTILITIES 1 My view of that would be that, as the 2 municipality is the shareholder of these entities, they 3 may be driven by non-commercial -- other social or other 4 concerns which may lead them to select a lower rate of 5 return. 6 MEMBER VLAHOS: Is this something, Mr. Mia -- 7 not this question, before, of Toronto Hydro -- is 8 this -- 9 What is the construct that the Board, or this 10 Panel, should go forward with? Should we have an end 11 state that all the utilities are on a commercial footing 12 and that profit maximizes? Or, for the next little 13 while, there will be a mixed bag of those? That there 14 will be different considerations: economic, for some; 15 social, for others; political, for yet others? 16 MR. MIA: I think our position would be that 17 if we start taking the part with different treatment of 18 different entities, that would sort of stray away from, 19 I suppose, the notion of fair and equal treatment of 20 all. So we stand behind the position that it shall be 21 treated as commercial entities, but with the recognition 22 that, at least in this transition period, there may be 23 other concerns, because we are moving from sort of a 24 public enterprise into a commercialized entity. 25 So, during that transition period, both for 26 the corporate entities and for the customers, there 27 probably will be need to take into account that 28 transition and give them some room to move. 106 COALITION FOR DISTRIBUTION UTILITIES 1 MEMBER VLAHOS: Thank you. 2 On page 5, again, under "Rate Adjustments", 3 when you talk about -- when you recommend a mechanism 4 that will allow deferred returns to be recovered in 5 later rate periods, can someone help me understand the 6 mechanics of it. How do you see it working? 7 MR. WILKIE: I believe what is meant by that 8 is that if you don't -- if you do not -- if the utility 9 did not select its maximum MBRR within a period, it 10 could then carry that over to, say, the next period in 11 its application and, thereby, have a greater MBRR than 12 what was previously done. 13 MEMBER VLAHOS: Is this something different -- 14 and I understand you gentlemen were here when Toronto 15 Hydro was here when it talked about a three-year 16 averaging. Is that the same concept or -- 17 MR. WILKIE: It could be. 18 I wasn't here when Toronto Hydro spoke about 19 that, but I believe there would have to be some period, 20 or window, the Board would have to allow for that to 21 occur. I mean they couldn't just carry them on 22 indefinitely forever. You would have to have some 23 period. 24 I think in the Toronto Hydro example, I 25 believe what they are talking about is if they were a 26 little less or a little bit more you would only look at 27 it over a three-year period. It would not necessarily 28 be an intentional attempt to take a lower rate of return 107 COALITION FOR DISTRIBUTION UTILITIES 1 over a prescribed period. 2 MEMBER VLAHOS: Again, what is wrong with the 3 proposition "use it or lose it"? 4 MR. WILKIE: Well, there may be nothing wrong 5 with that, it's just a point of view. 6 MEMBER VLAHOS: Moving over to the cap on 7 return on equity -- that is page 7 of your submission -- 8 you want to see the cap as simply a threshold beyond 9 which further gains would be shared between the utility 10 and customers. 11 My question here is: If that is the case, 12 then should the menu of productivity choice and rate of 13 return allowed under that choice, should that menu 14 survive? Do you want that sharing on the top of the 15 menu that is afforded now in the PBR Handbook as 16 proposed? 17 MR. WILKIE: The only time that I would see 18 that you would want to have the choice for the rate of 19 return would be if you had -- you wanted to encourage 20 amalgamation of utilities and you used that as a tool to 21 do that and to effect the cost savings. 22 MEMBER VLAHOS: Okay. Thank you. 23 On productivity factor, which is page 8, you 24 talked about the need for some flexibility in the event 25 that a system does not wish to price at maximum. 26 Keeping that in mind and going down to the 27 statement that it is absolutely crucial in the 28 Coalition's view that a productivity factor or any other 108 COALITION FOR DISTRIBUTION UTILITIES 1 factor in the formula should be accurate, it is crucial 2 to be accurate, I just need some help with that. 3 I did ask some information from Toronto Hydro 4 to give me some idea as to what the impact would be by 5 being wrong, if you like, by 1 per cent on any of those 6 two factors, being productivity or inflation. We don't 7 have that number yet. Do you have a sense of what the 8 number may be? Does anybody? No. 9 MR. MIA: No, we wouldn't have any numbers 10 on that. 11 MEMBER VLAHOS: Do you feel that it would be 12 substantial or material? 13 MR. WILKIE: Well, a 1 per cent I wouldn't 14 deem to be material. I'm sure a lot of other 15 accountants would agree with me on that. 16 But we haven't been able to study it and come 17 up with what would be appropriate. 18 MEMBER VLAHOS: Okay. I have read that 19 section and I have listened this morning, gentlemen, and 20 I'm not sure exactly what you are asking the Board to do 21 by way of a choice of productivity factor. A good 22 discussion, I'm just not sure what you are recommending 23 at the end of the day. 24 MR. MIA: I don't think we are recommending 25 anything different or asking the Board to do anything 26 different. We are just sort of -- the tone of the 27 submission was just recommending caution and moving 28 forward prudence. 109 COALITION FOR DISTRIBUTION UTILITIES 1 MEMBER VLAHOS: Okay. Thank you. 2 I guess the caution that the Board will have 3 to exercise is based on all the other considerations, 4 including the potential impact of being wrong. 5 MR. MIA: Yes. 6 MEMBER VLAHOS: Okay. Thank you. 7 On the service quality -- which starts on 8 page 9, and I'm turning over to page 10 -- the Coalition 9 would support the development of a wider approach which 10 would more accurately measure customer satisfaction. 11 Then later you talk about some kind of a standard form 12 of a survey, a questionnaire if you like. 13 Is this questionnaire, this survey, to 14 replace what has been proposed in the PBR or is it in 15 addition to? 16 MR. MIA: I think the gist of our 17 recommendation is that we don't want to get caught into 18 counting numbers. We are not against what has been 19 proposed, we think those are legitimate criteria, but 20 not the only criteria and to sort of see how they fit 21 together. 22 We are just concerned that if someone doesn't 23 hit the numbers as they are laid out in an abstract 24 sense that they are considered poorly in terms of 25 service quality when in fact their customers are happy 26 with the service they are getting and they are actually 27 providing good service. 28 We are just recommending sort of a fuller 110 COALITION FOR DISTRIBUTION UTILITIES 1 approach to weighing customer satisfaction. 2 MEMBER VLAHOS: It would be interesting if the 3 numbers turned poor but the service turned positive. 4 Who wins? 5 MR. MIA: Not likely. 6 MEMBER VLAHOS: I guess my last question in 7 this area is: Who is going to do this survey? Who is 8 going to design it? What frequency? What is the cost? 9 Has anybody turned their minds to it? 10 MR. MIA: I can start and I think maybe Neil 11 can assist. 12 I would think that obviously you would want a 13 sort of uniform approach. Obviously in this context the 14 Board would, I think, design it, but obviously with 15 input from distributors and, of course, try to capture 16 some of the local differences because of whatever 17 reasons, geographic or system size, customer type, 18 et cetera. So I think some sort of co-ordinated 19 approach similar to what we have seen with the PBR where 20 the Board drafts something in co-ordination with 21 distributors. 22 I haven't turned my mind, Neil may have, in 23 terms of frequency and how this is actually undertaken. 24 MR. SANFORD: I think that approach is what we 25 intended. Perhaps the MEA may have a role to play in 26 this. I know the OEB and the MEA have worked together 27 on a number of things. 28 This question of service quality is something 111 COALITION FOR DISTRIBUTION UTILITIES 1 that we have wrestled with for a long time and have used 2 surveys internally within utilities and have tried to 3 develop some standard models that different utilities 4 have applied. So I think that there is room for that to 5 be developed between the OEB and possibly the MEA as a 6 good representation of the distribution utilities. 7 MEMBER VLAHOS: Do you have any sense as to 8 what the cost burden would be on a small system? 9 MR. MIA: Could you repeat your question, 10 please? 11 MEMBER VLAHOS: Repeat my question? 12 MR. MIA: Yes, please. 13 MEMBER VLAHOS: Do you have any sense as to 14 what the cost may be, the burden, on the smaller system 15 of having to undertake such a survey on a periodic 16 basis? 17 MR. SANFORD: No, but I think once the form is 18 developed the normal survey techniques that are applied 19 within a community, I don't think there are huge costs 20 associated with that when you send things out, perhaps 21 in a mailing, but you have to recognize the likely 22 responses you would get. It's something that utilities 23 do at the moment. 24 MEMBER VLAHOS: The tabulation analysis I 25 guess will be taking place at some other place, not the 26 utility but the MEA. Is that what you see? 27 MR. SANFORD: It could be summarized and then 28 forwarded to the Board. 112 COALITION FOR DISTRIBUTION UTILITIES 1 MEMBER VLAHOS: Gentlemen, I don't know how 2 many of you were here when I asked Toronto Hydro some 3 general questions about implementation of the PBR. One 4 gentleman was not here, I'm not sure about the others. 5 But in terms of going in rates as well as 6 adjustments to the rates, do you have any comments as to 7 what you have heard? 8 MR. MIA: I don't think I was here for that 9 discussion. 10 MEMBER VLAHOS: Okay. The question was 11 whether the Board -- or what was the expectation of the 12 Board in exercising its authority in this PBR regime? 13 Would the Board approve or fix specific rates for a 14 specific utility or would the Board simply set a cap and 15 the specific rates will be subject to -- or it would be 16 up to the utility to set the rates without even coming 17 to the Board? That was the question, the general 18 question. 19 Can I get your views as to what your 20 expectations were or are? 21 MR. SANFORD: I think the Toronto reply to 22 that was that they expected it to be a maximum level 23 would be set and the individual utilities would be able 24 to set rates up to that maximum. 25 MEMBER VLAHOS: That's right. And Toronto 26 Hydro spoke of $1.00 per unit charge overall for the 27 utility not per rate class. Is that your understanding 28 as well? 113 COALITION FOR DISTRIBUTION UTILITIES 1 MR. SANFORD: Yes, that is. 2 MEMBER VLAHOS: That is? 3 MR. SANFORD: Yes. That seemed to fit the 4 model of somewhat light-handed regulation and then 5 giving some authority to the local community through the 6 LDC. 7 MEMBER VLAHOS: Some of you were here when 8 Pollution Probe gave its submission. Do you have any 9 comments in terms of the feasibility of a smaller system 10 than Toronto Hydro and I suggest pollution is about the 11 middle tier is it, Mr. Mia? 12 MR. MIA: Yes, most of us would be middle 13 tier. 14 MEMBER VLAHOS: Do you know whether any of the 15 systems in the coalition do offer DSM programs or are 16 they thinking of offering DSM programs? 17 MR. SANFORD: We certainly do in Oakville. We 18 have controlled electric water heaters as part of a DSM 19 program for many, many years. We are wrestling 20 somewhat. I think the comments made by Pollution Probe 21 were valid. We are wrestling, as I said, on how we are 22 going to accommodate that side of the business that we 23 currently do in water heaters within this new regime, 24 whether it would be in an affiliate. 25 The commentary that we made here on street 26 lighting with the accounts in Appendix B for street 27 lighting shown in the wires business leads us to some 28 justification that street lighting is in the LDC. 114 COALITION FOR DISTRIBUTION UTILITIES 1 I note that water heater maintenance is also 2 shown in that Appendix B as well. So that would 3 indicate that it would be in the LDC, which is somewhat 4 contrary to what I thought would happen with water 5 heaters, but relating that back to DSM I am somewhat at 6 a loss as to how we are going to incorporate and take 7 advantage of that facility in the new regime. 8 MR. MacKENZIE: At Guelph Hydro we have 9 participated in a number of DSM-related activities and 10 we have some staff engaged in DSM providing energy 11 audits and energy efficiency programs for our customers. 12 Frankly, we are somewhat puzzled at this point as to how 13 we are going to deal with that in the future. We don't 14 see it strictly as a wires-related business. We don't 15 see it as a business of an LDC. 16 But, on the other hand, we are somewhat 17 sympathetic to an approach that would improve energy 18 efficiency, not just from our customers' point of view, 19 but I guess from a societal point of view and we are not 20 sure where that fits within our future. 21 As I understand the Act as it is written, the 22 DSM doesn't have a place in a wires company. I heard 23 some of Mr. Gibbons' comments, but I don't see DSM being 24 part of a wires business yet. I am very sympathetic to 25 the fact, am very supportive of the need for DSM 26 activity, but I just haven't got my head around where it 27 should be within all of the LDCs in Ontario, 28 particularly within Guelph Hydro and the successors to 115 COALITION FOR DISTRIBUTION UTILITIES 1 Guelph Hydro. 2 It's still a dilemma for us. We have been 3 quite active in that for a number of years. I wouldn't 4 like to see us lose that within our own particular 5 community. 6 MEMBER VLAHOS: Was DSM a specific issue that 7 was sort of visited with your previous regulator, 8 Ontario Hydro? Did it have a high profile? Were the 9 costs separated and reviewed by Ontario Hydro? 10 MR. MacKENZIE: Demand-side management was 11 very much an initiative that was promoted and supported 12 by both Ontario Hydro and municipal electric utilities. 13 Some utilities embraced it more than others, but it was 14 certainly something that was promoted and supported by 15 Ontario Hydro in the role as a supplier and also in the 16 role as a regulator. 17 MR. SANFORD: They introduced financial 18 incentives to back that philosophy as well. 19 MEMBER VLAHOS: Directed to the customers or 20 to the utilities? 21 MR. MacKENZIE: Mostly directed to the 22 customers through the utilities. So if we had, for 23 example, a customer participate in an energy efficiency 24 project, there would be an incentive cheque available to 25 the customer when the project was up and running. That 26 was generally presented to the customer by both Ontario 27 Hydro and the local utility, but most of the funding 28 would come from Ontario Hydro. 116 COALITION FOR DISTRIBUTION UTILITIES 1 MEMBER VLAHOS: Thank you. 2 Thank you, gentlemen. Those are my questions. 3 Thank you, Mr. Chairman. 4 THE PRESIDING MEMBER: Can I just clarify that 5 last one. The funding for the incentives came from 6 Ontario Hydro for the majority of the municipalities? 7 MR. MacKENZIE: For the incentive, not for the 8 local utility effort, not for the local staff say at 9 Guelph Hydro or Oakville Hydro, but for the cheque that 10 was cut for the customer which would help the payback on 11 the particular energy incentive program would be from 12 Ontario Hydro. 13 I guess in today's world that would be OPG. 14 THE PRESIDING MEMBER: But the costs of the 15 customer contact was covered by the municipal utilities? 16 MR. MacKENZIE: The cost of the customer 17 contact and all of the promotional efforts within the 18 local municipality would be covered by the local 19 utility. 20 THE PRESIDING MEMBER: Dr. Zerker. 21 MEMBER ZERKER: Thank you. 22 Good afternoon. 23 Could I start with one question following up 24 on Mr. Vlahos' question on rate adjustment. Can you 25 hear me? 26 If in the outcome of events there is no 27 averaging of the rate of return, can you conceive of a 28 deferral account method through which this problem, as 117 COALITION FOR DISTRIBUTION UTILITIES 1 you pose it, could be dealt with? 2 MR. WILKIE: Yes. 3 MEMBER ZERKER: I would like to ask you a 4 question on this hot topic, contributed capital. We 5 know all the different -- we have heard from various 6 sources and all the different points of view that go 7 from one extreme to the other. You take the position 8 that all capital investments in Ontario were paid for by 9 customers. 10 In the interests of fairness would you not 11 agree or does it matter to you that it was specific 12 customers that paid for contributed capital, not all 13 customers? 14 MR. SANFORD: Specific customers paid for 15 specific contributed capital? 16 MEMBER ZERKER: Contributed capital, yes. 17 MR. SANFORD: For facilities that served them 18 as new customers onto the system. 19 MEMBER ZERKER: Right. 20 And in the proposal that you make it would be 21 all customers that would somehow now have to take 22 account of that initial contribution, is that correct, 23 through using uniform rate on all capital, return on 24 capital? Would that not be true, that all customers, 25 those who did not benefit and those who did already 26 benefit, that they would all have to pay an equivalent 27 amount for that? 28 MR. SANFORD: They would, yes, but I would add 118 COALITION FOR DISTRIBUTION UTILITIES 1 one point on that too. The fact that specific customers 2 were making specific contributing capital that helped 3 keep rates down for the other customers. So the other 4 customers in the past have had the benefit of lower 5 rates because the utility was infused with contributed 6 capital from specific customers. 7 MEMBER ZERKER: I see. So that, therefore, 8 you see this fairness as now balancing out what had 9 happened in the past? 10 MR. SANFORD: If we get a return on all -- 11 MEMBER ZERKER: I mean using your proposal. 12 MR. SANFORD: Yes, but that's not going into 13 the treatment of future contributed capital. 14 MEMBER ZERKER: No. 15 MR. SANFORD: That's past. 16 MEMBER ZERKER: In the treatment of future 17 contributed capital I am not 100 per cent clear. You 18 accept the principle that contributed capital will only 19 receive the maintenance costs of contributed capital in 20 the future. Is that correct? 21 MR. WILKIE: Yes. 22 MEMBER ZERKER: Thank you. 23 On return on equity you propose a sharing 24 mechanism. What kind of sharing mechanism do you have 25 in mind? You haven't got any specific proposal there, 26 but I wondered if you had a specific proposal in mind, 27 50/50, 40/60 or a range of them or a flexible pattern of 28 some sort. Did you have any suggestions on the kind of 119 COALITION FOR DISTRIBUTION UTILITIES 1 sharing that you had in mind? 2 MR. MIA: I think the consensus here would be 3 50/50, sort of a 50/50 split between the customer and 4 distributor. 5 MEMBER ZERKER: And without any kind of 6 variation over the range of possible surpluses over the 7 cap? Would it be say -- you have no idea of 25/75, then 8 50/50, then 75/25 or anything of that sort? 9 MR. MIA: At this point we haven't looked at 10 it in that detail. 11 MEMBER ZERKER: Could I turn to the 12 productivity factor and your analysis, which suggests 13 that there is very little room for productivity gain. 14 What kind of conclusion comes from that? Does 15 that add up to saying that you would think that the 16 productivity factor should be considerably lower? 17 I mean, I want to know what you conclude from 18 your evidence. 19 MR. WILKIE: That's correct. It has always 20 been my feeling that it should be lower, that it's too 21 high at 1.25. 22 MEMBER ZERKER: So it's not simply a matter of 23 accuracy, accuracy in some generic sense. You are 24 thinking in terms of some kind of lower productivity 25 factor -- 26 MR. WILKIE: Yes. 27 MEMBER ZERKER: -- because it is impossible, 28 or at least you suggest that there is a limit to how 120 COALITION FOR DISTRIBUTION UTILITIES 1 much productivity gain is possible. 2 MR. WILKIE: Exactly. 3 MEMBER ZERKER: What would then be your ideas, 4 or at least some ballpark figure, of what kind of 5 productivity figure you would have, would be more 6 satisfactory to you? 7 MR. WILKIE: I'm sorry, but we haven't come up 8 with anything. I think anything that was maybe lower 9 than the 1.25 would probably be good. It is really said 10 very respectfully from the fact that we have had -- I 11 know in Niagara Falls anyways we have had six years now 12 where we haven't had a rate increase. During that time 13 we have absorbed what has been rate increases from 14 Ontario Hydro -- not actual rate increases, but just a 15 taking away of services that they used to provide. 16 We touched a little bit on it in the demand 17 side management question and we did employ someone in 18 that regard. That individual was going around doing 19 those services in the community. And about two years 20 ago we had a person retire, so we moved him out of the 21 job and moved the other fellow over to get some cost 22 saving, some efficiency gains, if you will. 23 So we took ourselves out of that sort of 24 service. It has been that kind of continual process 25 that the local utilities have gone through. 26 A lot of it is driven by the municipal owner. 27 You know, we have just effected some of those gains 28 already. So I would suspect and I believe strongly that 121 COALITION FOR DISTRIBUTION UTILITIES 1 there is only minimal ones left. 2 To have a productivity factor that applies to 3 many fixed costs means that you will have to see greater 4 efficiency from I guess the variable portion of our 5 expenses. 6 MEMBER ZERKER: I hear something in what you 7 have just told me, that productivity gains were and are 8 likely to come from a reduction in services. 9 MR. WILKIE: I think ultimately it has to. I 10 mean, if -- it's not an industry that has a lot of -- 11 that technology plays a big part of. There is generally 12 a perception that maybe in metering you can do things on 13 a more technological basis. 14 But it is still the cheapest way to get at a 15 customer's reading, the average customer in a 16 residential neighbourhood, is to go out and actually 17 read it, have somebody or have a contractor do it. That 18 is what we do in Niagara Falls is we have a contractor 19 who goes and reads those. I mean, they are charging 20 35 cents per read. I don't think there is a lot of gain 21 in that particular example that you can squeeze too much 22 more out of it. 23 The only way you can get at some efficiencies, 24 gains in that respect, would be to read two at once, 25 say, an electricity meter and a gas mater, or a water 26 meter. 27 MEMBER ZERKER: Well, then, what do you 28 foresee? Your next section is about service quality and 122 COALITION FOR DISTRIBUTION UTILITIES 1 the maintenance of service quality. Is there an inherent 2 conflict between the service quality maintenance and 3 productivity gains, in your view? 4 MR. WILKIE: I think there is, yes. I think 5 there could be. And utilities will have to balance how 6 much they want to effect those productivity efficiency 7 gains at the expense of service quality. 8 MEMBER ZERKER: What do you think the Board 9 ought to do? Because it is the Board's function to 10 protect, and certainly service quality is an important 11 element of protecting a public interest. 12 Have you any suggestions, as experienced 13 utility management, on how the Board ought to go about 14 balancing these conflicting aspects of the plan as its 15 coming forward? 16 MR. WILKIE: I don't think it will be easy. 17 It will be very difficult for you to balance them. 18 Maybe for that reason that is why we have suggested for 19 you to be very cautious in how you and where you set 20 your productivity factor because there may be some -- 21 you may have some concern about how that will impact 22 what we do as utility things. 23 MR. SANFORD: Can I just add? 24 The service quality factors that you have said 25 I think are appropriate and I know they were set with a 26 fair amount of consultation with utilities and the MEA. 27 I don't think any of us have too much of a 28 problem in certainly maintaining or even better than the 123 COALITION FOR DISTRIBUTION UTILITIES 1 service quality standards identified. I think when you 2 put the two positions together as you have, the service 3 quality and the productivity improvement, our concern is 4 on the productivity improvement. 5 To reiterate Brian's point again, and I think 6 Niagara Falls is typical of most of our utilities, when 7 we haven't had rate increases for six years, and there 8 has been obviously CPI and all those inflationary things 9 over that period of time, we have demonstrated 10 productivity improvements already and they are kind of 11 pushed to the limit. 12 But I don't think any of us are really 13 expecting that service quality will go down. That has 14 been our mandate in the past and I think we all accept 15 it as being in the future. But it is the -- 16 MEMBER ZERKER: So under the fixed regime that 17 you have been through, that is where you have found the 18 difficulties in maintaining the service quality. Is 19 that what you are saying? 20 MR. SANFORD: No. We didn't have a difficulty 21 in doing it. I think we have done it, the efficiencies 22 that we have made in utilities by technology and, in 23 many cases, good management and better use of people. 24 MEMBER ZERKER: Then there are opportunities 25 that you have had in the past. Does that mean that you 26 feel that those opportunities have been exploited? 27 MR. SANFORD: I think, to a large extent, yes. 28 When you go six years with no increase, yes. 124 COALITION FOR DISTRIBUTION UTILITIES 1 When you are into a people business, which 2 utility business is -- it is management of people -- 3 there is a limit to how far you can go in efficiencies 4 when 80 or 90 per cent of our utility expenditures are 5 people costs. So I think we are fairly at the limit. 6 MEMBER ZERKER: Thank you. 7 I wondered, when you were talking about a wire 8 approach for service quality, if you had any principle 9 behind that. I'm not asking for any specific because 10 you are suggesting that the Board look into this, but I 11 wondered what it is you mean by a "wider approach". 12 Does it include some kind of consciousness of 13 the social welfare needs of the society? What is it 14 that you mean by the "wider approach"? 15 MR. SANFORD: I didn't think it was that wide. 16 --- Laughter 17 MR. SANFORD: But the surveys that we have 18 done as an industry, having included comparisons with 19 other service utility industries, a number of utilities, 20 through the MEA, have done surveys where we can 21 certainly equate customer satisfaction for the electric 22 utility against telecommunications, cable tv, Union Gas, 23 or gas companies, that kind of survey. 24 So we know where we stand on those kind of 25 scales at the moment. I think a continuation of that 26 kind of thing could be helpful in determining service 27 quality. 28 Certainly the expectations within different 125 COALITION FOR DISTRIBUTION UTILITIES 1 communities -- and this goes back a little bit to 2 Toronto Hydro's discussion on how they are a different 3 utility than Ontario Hydro Services, for instance -- the 4 levels of service and reliability that cottage 5 customers, for instance, experience is certainly vastly 6 different from the expectations from downtown Toronto. 7 Each of us in our utilities have those kind of 8 differences as well. 9 So they are set very often by the local -- the 10 standards have already been set by the local community 11 and by the customers in that community. 12 MEMBER ZERKER: I would turn you to page 12 of 13 your submission and your analysis that electricity 14 prices in Ontario will rise. As you know, that is not 15 the objective of the government. 16 Would it be fairer to say that electricity 17 distribution prices will rise? We don't know -- or do 18 we know -- that electricity prices, including the 19 commodity, will rise. Or is there any hope that they 20 will not rise if the competitive end of the industry 21 becomes as designed or as expected? 22 I would like to know what you think as 23 experienced operators in this industry. 24 MR. SANFORD: I think your assumption that 25 distribution prices will rise is a certainty in our end 26 of the business. But when we look at the overall 27 electricity prices -- and I think the other managers 28 here would want to make comment on this as well -- the 126 COALITION FOR DISTRIBUTION UTILITIES 1 models that have been done so far, the 3.8 cent cap that 2 is there from OPG, we are not really at this point in 3 the market as it will open next year -- we don't have 4 the competition in generation that this model foresaw 5 originally. 6 I think we would all be unanimous in that 7 electricity prices in the short term will rise, then 8 erode as we get some competition in generation. That 9 has been, I think, all our positions in the past; that 10 the purpose of Bill 35 was to introduce competition 11 where there are the most costs. 12 At the moment, generation is 70 per cent of 13 the cost of electricity. That is where we need 14 competition. Retail competition is going to do 15 virtually nothing, I don't think, for competitive 16 pricing. 17 Jim...? 18 MR. MacKENZIE: I would agree with Neil. I 19 truly believe in the short term that the end price to 20 the customer, all-in price to the customer, will 21 increase as a result of the current restructuring. 22 I think over the long term -- and we are 23 looking anywhere beyond five years before we will see 24 the reduction in the commodity price that will offset 25 the increase in the costs of distribution, transmission, 26 the need for establishing prudential requirements, and 27 the increased number of transactions and the increased 28 transaction costs that result from the new market. 127 COALITION FOR DISTRIBUTION UTILITIES 1 I think if you take a look at the whole price 2 that a customer pays, the commodity prices have to come 3 down significantly to offset what I expect to be 4 increases in all the other aspects of the business. 5 Ultimately, that might happen. But it will be 6 at least five years. I think that presents a tremendous 7 challenge for the OEB and for us as local distributors. 8 Likely we are the ones who are going to have to explain 9 all of this to our local customers, and that is the 10 challenge for us. 11 MEMBER ZERKER: So will the Board. 12 MR. MacKENZIE: Yes. 13 MEMBER ZERKER: Thank you very much. Those 14 are my questions. 15 MEMBER VLAHOS: Is it Mr. MacKenzie? 16 MR. MacKENZIE: Yes. 17 MEMBER VLAHOS: Sorry, it is the gentleman to 18 the left of Mr. Mia. 19 MR. SANFORD: Neil Sanford. 20 MEMBER VLAHOS: I want to follow up on the 21 statement that you made that retail competition will do 22 nothing for the customer. 23 You were speaking about price. It was in that 24 context, was it? 25 MR. SANFORD: Yes. In the short term 26 initially, when the market is supplied by OPG 27 predominantly, I don't know how anybody is going to get 28 any real retail competition. 128 COALITION FOR DISTRIBUTION UTILITIES 1 MEMBER VLAHOS: You are not questioning the 2 sort of value-added in the long term at the end stated 3 model. 4 MR. SANFORD: No. 5 MEMBER VLAHOS: Thank you. 6 THE PRESIDING MEMBER: I think my colleagues 7 have asked all of my questions. 8 That leaves it to me to thank you for your 9 appearance and for your help. 10 There is nothing else, is there, Ms Kwik, that 11 Board staff requires? 12 MS KWIK: No, Mr. Chair. 13 THE PRESIDING MEMBER: Thank you for your 14 presentation. We found it very useful and helpful. I 15 am sorry that we were late starting. 16 We will close now and come back at 1:45. It 17 is only 45 minutes and I apologize. 18 Thank you. 19 --- Luncheon recess at 1255 20 --- Upon resuming at 1350 21 THE PRESIDING MEMBER: Good afternoon, 22 Mr. Poch. 23 MR. POCH: Good afternoon, Mr. Chairman; good 24 afternoon, Panel. 25 THE PRESIDING MEMBER: The ball is in your 26 court. 27 PRESENTATION 28 MR. POCH: Thank you very much. 129 GREEN ENERGY COALITION, Presentation 1 I have taken advantage of your offer to allow 2 us make oral submissions as well as subsequent written 3 submissions, and I am going to try not do the same thing 4 twice. Since you have already seen it in my earlier 5 submissions and in cross-examination, I am sure that the 6 boredom factor will be counter productive for me. 7 I will, in subsequent written submissions, try 8 to touch on a number of items that I won't go into any 9 detail today with you on. I just want to emphasize that 10 we have some quite serious concerns in a number of other 11 areas, other than the DSM issue, which I would like to 12 focus on. 13 The contributed capital issue, we are very 14 concerned; we would like the price signal to be right, 15 the long-run marginal cost price signal. We tend to 16 agree that the distinction between contributed capital 17 and capital that was built up through rates is a pretty 18 slippery slope, and we prefer to see the full costs of 19 capital reflected in the rates -- in the end rate, I 20 should say. 21 We are very concerned about what appears to be 22 a dramatic shift in how much the rate for residential 23 customers, certainly the ones on energy meters, is going 24 to be collected through the fixed customer charge. 25 One element of that is this issue of how the 26 IDC is calculated. Mr. Chernick speaks to this in the 27 appendix to his evidence, and I will come back to it in 28 a few minutes. I know that there is some debate about 130 GREEN ENERGY COALITION, Presentation 1 what is or isn't or was or wasn't included in that 2 study, but there are quite a number of criticisms that 3 Mr. Chernick makes about that study; its treatment of 4 capitalized overheads. He says it doesn't include 5 losses from a plain reading of it. 6 I understand from Ms Kwik that as the 7 derivation of this number came through, she is 8 reasonably confident that losses have been treated 9 properly. In fact, Mr. Chernick's appendix shows how 10 the study that doesn't include losses works out to 11 exactly the same number as the .62. 12 So it makes me concerned that losses haven't 13 been dealt with. In any event, they probably haven't 14 been dealt with as marginal losses which are, given the 15 square law, which I will leave to the engineers, are 16 quite different than average losses. 17 I understand Mr. McGee, who represents FOCA 18 and will be speaking to you later, has taken the trouble 19 to try to look at what the IDC imbedded in rates 20 throughout the province has actually been. He derives a 21 number roughly twice the .62. 22 There is a healthy debate there that is beyond 23 my capabilities, and I am really just alerting you that 24 maybe that is a number that needs to be revisited. It 25 would have dramatic consequences for the price signal 26 for conservation. If most of the distribution costs are 27 fixed and unavoidable, obviously the signal is watered 28 down for conservation. 131 GREEN ENERGY COALITION, Presentation 1 I am also going to assume that the Board is 2 reasonably familiar with the arguments why we have had 3 DSM brought to us by utilities on the electric side in 4 the past, in Ontario at least, and still to this day by 5 some of the municipal utilities -- when I say the past, 6 I meant the old days of big Ontario Hydro -- and why we 7 have it on the gas side. 8 Mr. Chernick does review those market barriers 9 in Section 2 of his paper brief where he lists in 10 bullets the various market barriers which persist, I 11 would suggest. 12 I would like to respond to the implicit 13 comment that came from Board staff and its advisors when 14 they said they want to see how the market is going to 15 bring us conservation. 16 Mr. Chernick does address this directly in his 17 evidence, and I have paraphrased it. Indeed, I think I 18 have mostly just copied it on page 1 of the written 19 version of my comments today. 20 He has listed there the reasons why the 21 private market can't be expected to do the job; in other 22 words, what market barriers will persist or what new 23 market barriers we might see. And I think it is worth 24 stressing. 25 First of all, if you are a retailer wanting to 26 do DSM, you are not going to be able to spread this cost 27 over a bunch of other customers. You are basically 28 going to have to get it from that one customer. 132 GREEN ENERGY COALITION, Presentation 1 This is true whether or not the benefits are 2 enjoyed by others, as they might be on the distribution 3 front if you can alleviate a bottleneck, as they 4 certainly are in terms of the environmental 5 externalities that are avoided. That is obviously not a 6 benefit that that customer enjoys solely; that is a 7 benefit shared by society. 8 The retailers, private enterprisers need to 9 recover costs. He is only going to do the cream of the 10 crop of DSM which has a fast payback for the particular 11 customer involved, not counting the broader benefits. 12 And then he is going to have to invest a lot of time and 13 effort explaining to a small residential customer why 14 this measure is going to pay off and it makes sense to 15 do. 16 Those are the kinds of transaction costs and 17 difficulties that utility DSM is designed to overcome. 18 The customer can basically not have to engage 19 in that kind of lengthy analysis about the cost 20 effectiveness for the particular customer. The utility 21 can take a formulaic approach. There is a lot of 22 efficiency in that. They might not get it right every 23 time, but they are going to be well above the average in 24 terms of achieving cost effectiveness, and that is 25 exactly why DSM delivered through a specialty entity 26 makes some sense. 27 Other barriers. The risks to one or both of 28 the parties, if the customer moves or changes suppliers. 133 GREEN ENERGY COALITION, Presentation 1 These measures typically have long paybacks. People we 2 know, people averse to upfront costs. One of the 3 benefits to the utility, of DSM, is being able to spread 4 those costs out in time and amongst players. A retailer 5 won't be able to do that because they may not have a 6 contractual relationship with this customer later on. 7 Inability of building owners and developers 8 who sign up for the efficiency services to obligate 9 tenants and purchasers to purchase the energy from 10 particular marketers. Presumably, the assumption here 11 is that the DSM is going to come along with some energy 12 purchasing contract. But this is sort of the new 13 version of the split incentive. We have different 14 players enjoying the benefits and facing the burden. 15 This information transaction costs are always 16 a problem. This is one of the primary market barriers 17 to cost-effective efficiency out there, that it's a 18 relatively small amount someone, any individual, might 19 save. A lot of the benefits, the motivation -- 20 certainly the motivation for my clients -- is to do with 21 the societal benefits, or the spin off. It's very hard 22 to expect customers to engage in that kind of lengthy 23 analysis -- and, in reality, they often don't. But when 24 you are going to your customers and expecting them to 25 pay for it, they are going to make you go through that 26 and it's going to take the profit away from a retailer. 27 There's just not going to be any margin left. 28 We hear, from the DSM experts, increasingly, 134 GREEN ENERGY COALITION, Presentation 1 about how "We want to move towards market 2 transformation-style DMS". Broad programs aimed at 3 changing the nature of the marketplace, so then it can 4 carry on on its own -- which, everyone agrees, is ideal 5 where you can do it. 6 But these are the kind of programs that you 7 need an entity to do that isn't trying to recover that 8 cost directly from the specific customers. It is 9 working on the assumption that the costs will be 10 widely -- the benefits will be relatively widely enjoyed 11 and that the costs can be charged fairly broadly. 12 Mr. Chernick also makes the point -- and I 13 have reiterated -- that non-utility companies may not 14 have sufficient financial incentive to serve many types 15 of customers; for example, low-volume and low-income 16 customers. There's just not going to be enough there 17 for them to bother with. But I believe that the Board 18 should properly be concerned about some degree of 19 universality of these benefits; that is, these benefits 20 being made available to all customers, particularly 21 disenfranchised customers. 22 And, of course, implicit in a number of things 23 I have said, the private sector just can't afford to 24 take account of externalities. Not that utilities -- as 25 we have seen on the gas side -- are anxious to take 26 count of them either, but they are a lot -- they are 27 willing to go a lot closer to the line of 28 cost-effectiveness, in terms of the narrow financial 135 GREEN ENERGY COALITION, Presentation 1 cost-effectiveness, given the comfort that they also 2 achieve in broader societal benefits -- and I think the 3 Board has taken comfort in that, as they did in the 4 discussion of the portfolio approach to system expansion 5 in gas; that was not, strictly speaking, as I recall, in 6 the formula, but it was something that gave everyone 7 comfort. 8 We have this history in Ontario. The latest 9 numbers from Enbridge, in the most recent filing -- and 10 I'm doing this from memory -- give us an estimate of 11 roughly $50 million in customer net, after cost/bill 12 savings, for each year of its DSM program. That's the 13 present value of the stream of benefits from one year of 14 utility DSM activity. And that is based on the TRC 15 test; that is without counting societal benefits of 16 reduced externalities. 17 Union's program of roughly equivalent scale, 18 if you add in the externalities, it roughly doubles it, 19 again. We are up to $200 million a year in societal 20 benefits. Half of which is in the form bill-saving, 21 half of which is in the form of reduced externalities -- 22 about which, I readily admit, there is great debate 23 about how you put a price on that, but it's a big 24 number. 25 All the experts agree, the history tells us, 26 the savings on the electricity front, even in a time 27 when we are not facing a capacity crunch, are more 28 significant than they are on the gas side. There are 136 GREEN ENERGY COALITION, Presentation 1 simply more customers and they spend more, so there's 2 going to be more savings. 3 I went back and looked -- and I think 4 Mr. Chernick recites this -- I went back and looked at 5 the last of Ontario Hydro's DSM savings that had the 6 scrutiny of this Board, in the early part of this 7 decade. I think it was at the time of HR-21 and HR-22; 8 we were facing a capacity surplus. The Board said, 9 nevertheless, it makes sense to do this so our loss 10 opportunities which need to be obtained or we lose the 11 chance to, you know, put in a more efficient fridge 12 before that investment decision is made and it sits 13 there for 15 years. And Hydro was spending something 14 like a quarter of a billion dollars, at the time, on 15 conservation, and it got this Board's blessing, even 16 though there was a lot of concern from I think the MEA, 17 amongst others, that maybe we shouldn't be spending any 18 money on DSM because we have a surplus. 19 So I think there's no question there's 20 tremendous savings to be had here and to delay it means 21 to lose some of those savings. 22 Faced with that, we are moving towards PBR, 23 which means that the incentive structure for utilities 24 is obviously changing. If there is a disincentive for 25 investment and conservation, it is now magnified by 26 reason of the fact that they are out for three years. 27 If they can trim a dollar by not spending some money on 28 conservation, they are going to trim it for three years 137 GREEN ENERGY COALITION, Presentation 1 before they have to come back before the board. 2 So the incentives are magnified -- which, of 3 course, is a benefit of PBR, in most cases, but, in this 4 case, our concern is it's a great disbenefit. And I 5 make the point that the interim approach of simply, in 6 effect, ignoring DSM is going to be -- could be very 7 regressive. 8 The mechanics. While there was some debate in 9 the technical conference about, in particular 10 situations, what the incentives and disincentive-facing 11 utility would be under the particular PBR regime we are 12 talking about here, price caps with a cap on return and 13 so on, there were pretty well agreements from all the 14 technical people they are going to have a disincentive, 15 and it comes for two reasons. 16 First of all, the variable component of rates 17 which is intended to be set on this IDC number, which 18 is, in turn, intended to reflect long-run marginal 19 costs, is much higher than the short-run marginal costs 20 that the utility faces. This was, with exceptions -- 21 always a caveat -- this was widely agreed to, that in 22 fact some went far enough -- I think Mr. Chernick said 23 the short-run marginal costs should be close to zero. 24 So, in an arrow, when we are moving these 25 utilities to behave more and more like commercial 26 entities, that short-term bottom line is only going to 27 figure ever more largely in the minds of managers of 28 these utilities. And they spend money on DSM, Even 138 GREEN ENERGY COALITION, Presentation 1 though it's rational expenditure, looking at your 2 long-run marginal costs, it's going to hurt you in the 3 short-term; we are going to take a profit hit. 4 I guess the other more obvious point that has 5 to be pointed to a few experts is: They have no way to 6 recover the money they are going to spend on the DSM. 7 Typically, DSM is expensed and -- at least in large 8 part. They have nowhere to collect that money. Even if 9 it's been forecast and included, somehow, they still 10 have the incentive not to spend it, pocket the money. 11 So, big disincentives. Unless the Board does 12 what it has done on the gas side. 13 You are familiar with those -- what you have 14 done on the gas side, the LRAMS, so that they don't have 15 this loss revenue problem, Mr. Chernick suggests another 16 formula you could use. That way, you basically allow 17 saved -- electricity savings to be included in the 18 kilowatt hours saved to be included in the denominator 19 when the utilities -- proving to your staff that they 20 stayed within their price cap. 21 The DSMVA. That is the variance account for 22 the expenditures -- the Z-factor, I guess it's now 23 called, more appropriately in this setting. An 24 incentive. A shared savings mechanism has been the one 25 that this Board has indicated its preference for and I 26 think most parties -- I think virtually every party 27 agrees is the way to go. 28 Now, Board staff raised a number of concerns, 139 GREEN ENERGY COALITION, Presentation 1 so I would like to deal with them square on. Their 2 first one being the complexity in costs for small 3 utilities. 4 We are not, at this point, advocating more 5 than a voluntary approach in Phase 1. We would differ 6 from Board staff, in that they say, well -- their 7 response was, "Well, utilities are free to come forward 8 and propose something". 9 We are asking that the Board invite utilities 10 who are interested in conservation to do so, so that 11 it's understood by utilities that they will have a -- 12 such proposals will be entertained by the Board and that 13 they aren't just creating problems. 14 For utilities that are smaller that do want to 15 get into this, or are already into it, the economies of 16 scale can be achieved in any number of ways: They can 17 contract this out to experts who are doing this -- who 18 are aggregating utilities; they can do it through MEA or 19 ENERConnect or some other entity; they can arrange 20 something with a larger utility that has the expertise 21 and is geared up already and is quite familiar with the 22 situation in Ontario. 23 There are any number of possibilities. Our 24 suggestion is, like in all areas of PBR, let their 25 creativity reign, give them the incentive, let them find 26 a way to do it most cost effectively. 27 The next point concerned Board staff raised 28 was the question of this risk of unfair advantage to 140 GREEN ENERGY COALITION, Presentation 1 affiliates. Apparently Mr. King, I believe it was, told 2 us that in Norway this became a problem of utilities 3 favouring their affiliate's energy customers with access 4 to DSM goodies and others not apparently getting the 5 same treatment. 6 Having the benefit of that experience I think 7 it is something the Board should explicitly guard 8 against in the Code of Conduct, to warn against. It is 9 something people are alert to. 10 I'm not sure how significant a problem it is. 11 I would say that with this move towards market 12 transformation style DSM programs tend to be -- 13 especially on the residential side, programs tend to be 14 cookie-cutter programs where, whatever it is, the coupon 15 program, the incentive to manufacturers to stock the 16 more efficient models, whatever it may be. These are 17 programs where it is not some customer-specific analysis 18 that can be played with to favour particular customer 19 groups. 20 So I think it is less a concern in today's 21 world. But certainly it would be appropriate to guard 22 against that in the Code of Conduct. 23 I will come back in a moment, but apparently 24 in Norway that was one of the motivations for going to a 25 kind of a regional DSM entity. 26 This really brings us to the third concern 27 that Board staff raised, which was the need or the 28 benefits of first considering whether it is -- 141 GREEN ENERGY COALITION, Presentation 1 distribution utilities are the appropriate delivery 2 vehicle for DSM. 3 Mr. King said, as a matter of fact -- I can't 4 remember his exact words, but I'm paraphrasing him 5 saying: Yes, there are market barriers, I have spent 6 15 years of my life designing programs to help overcome 7 them. He now favours this regional approach. 8 Well, let me start off by saying the regional 9 approach may well be a good idea, but should we just 10 stop the clock and wait for such a thing to spring up 11 somehow and lose this time and lose the -- and meanwhile 12 disincent utilities. 13 Here is the history that we have before us: 14 We have both Acts saying that this restructuring and the 15 Board's role within energy regulation should facilitate 16 energy efficiency and a move towards cleaner generation. 17 We have never had that before. So the Board, to some 18 extent, has its orders. 19 We have the Board's decisions on the gas side. 20 Everybody agrees we should be looking at a level playing 21 field here where the Board has called upon the gas 22 utilities to do DSM and has given them the incentive. 23 We have the Board's decision last year in the 24 interim rates proceedings for OHSC, and I would like to 25 read some of that into the record for you. I quote, and 26 this is from page 70 of the decision. I think it is of 27 the distribution decision, although I think the words 28 are pretty well the same in both the distribution and 142 GREEN ENERGY COALITION, Presentation 1 the transmission decision. 2 Quote: 3 "The Board recognizes that consideration 4 of DSM is appropriate given the Board's 5 role of facilitating energy efficiency as 6 stated in the Purpose section of the Act. 7 However, the Board is also currently 8 considering the details of various 9 Performance Based Regulation 10 methodologies for electricity 11 distribution utilities, and has been 12 presented with an initial proposal for 13 PBR for transmission. The Board notes 14 that discussions in some of the workshops 15 have considered the issue of providing 16 incentives for DSM as part of the PBR 17 mechanism. The Board is hopeful that a 18 DSM/energy efficiency incentive mechanism 19 can be designed that (i) meets the 20 majority of concerns of interested 21 parties, (ii) provides the electric 22 distribution utility with an incentive to 23 pursue these goals, and (iii) results in 24 net benefits. Such a mechanism must be 25 compatible with the Boards stated 26 requirements (e.g. easily understood, 27 transparent, simple, etc.) for any 28 PBR methodology chosen. The Board is of 143 GREEN ENERGY COALITION, Presentation 1 the view that consideration of a 2 DSM/energy efficiency incentive mechanism 3 in the Board's PBR stakeholder workshops 4 is an appropriate way to address the 5 issue since any mechanism implemented has 6 the potential to impact all electric 7 distributors. The Board is of the view 8 that any PBR mechanism proposed for 9 transmission should incorporate 10 consideration of any Board-approved 11 PBR mechanisms for electric distribution, 12 including any specific considerations of 13 DSM/energy efficiency incentives if 14 appropriate." 15 So I think Board staff largely ignored that 16 decision of the Board only a year ago in the midst of 17 restructuring, and consequently ignored the 18 recommendations from the task force which the Board 19 refers to there, the implementation task force, which 20 suggested precisely what we are suggesting here: It 21 should be voluntary now and that in Phase 2 we should be 22 looking at some broader implementation. 23 I think there is widespread acceptance of the 24 idea, and the Board has previously acknowledged that. 25 and it would be, you know, a one step forward two steps 26 backwards situation if we had to go back now, have yet 27 another round, and perhaps spend another year before we 28 can institute this. 144 GREEN ENERGY COALITION, Presentation 1 As it is, with a voluntary approach I don't 2 think we are going to see, you know, the floodgates 3 opening here. There are a very few utilities who are 4 likely in a position in the midst of everything that is 5 going on to gear up a DSM program. 6 But I think it would be a very positive 7 statement for the Board to invite those who are in a 8 position to do so to do so: One, because we don't want 9 to lose those actual benefits; and, two, because it will 10 get the sector thinking about this, and then I believe 11 the Board should put it on the agenda for the 12 discussions, the midterm discussions that everyone 13 anticipates for the second generation. Where do we go 14 with DSM in this sector. 15 But I think if the Board doesn't enable 16 activity amongst those who want it now, we are going to 17 be delaying the subsequent steps, should there be any. 18 Now, I apologize, I see in my written script 19 here I got upset with Board staff and make a quip about 20 how apparently we have to be perfect in DSM and yet they 21 relied on this IDC study with all these problems and not 22 even having read it, and I must apologize. That was a 23 bit harsh. 24 But I think that nevertheless the contrast is 25 important, that we are moving towards PBR, we all 26 recognize this first generation PBR is going to be far 27 from perfect, we are prepared to move ahead with some 28 form of PBR -- some aren't, but most of us are prepared 145 GREEN ENERGY COALITION, Presentation 1 to move ahead with some PBR form because we realize it 2 is important to get going down that road. 3 The "learn by doing approach" I think is how 4 the Board paraphrased it on the DSM front with the gas 5 utilities, and I would suggest we do the same with DSM. 6 Now, coming back to the suggestion of a 7 regional approach for DSM, and the example Mr. King gave 8 was Norway and I think Vermont came up as the other 9 example where they have gone to some kind of regional 10 approach. 11 Mr. Chernick pointed out in his oral evidence 12 that the Vermont approach indeed wasn't one that came 13 down from on-high from the State government or even from 14 the regulator, it grew out of the regulators saying to 15 utilities -- and it isn't a PBR regime, it's a 16 traditional regulatory regime there, cost of service 17 regime -- it told these utilities -- and there are many 18 of them there, it is analogous to our distribution 19 situation here -- we want you to do DSM. 20 Some of them felt they couldn't demonstrate 21 that they were doing it well enough, others wanted to 22 achieve economies, and they came to this in a kind of 23 multi-stakeholder discussion as a solution that appealed 24 to everybody. 25 I gather -- I don't know that it has received 26 the formal blessing of the regulator there yet, but I 27 think it is anticipated that that is a formality. 28 Now, it may well be that that evolves here, 146 GREEN ENERGY COALITION, Presentation 1 and that would be a good thing, in our perspective. But 2 I think it would be something that will have to evolve 3 from the bottom up. I don't think it is realistic to 4 expect the government is going to be particularly 5 interested in mandating a new public institution at this 6 time. Let it emerge if it is felt by the players to be 7 a cost effective way of delivering, of delivering the 8 goods. 9 The perhaps more realistic alternative is -- 10 it wasn't discussed in the technical conference, but I 11 guess it was in people's minds -- is that the 12 transmission utility could be responsible. 13 Certainly the Board in its interim decisions 14 on transmission and distribution for OHSC recognized 15 that possibility, that there are going to be activities 16 by both the transmission entity and distribution 17 entities and that these should dovetail. 18 We would agree that there may well be a role 19 for the transition utility given its provincial level of 20 activity, but, in any event, we don't want to be setting 21 up a disincentive for distribution utilities to play 22 some role in that. They are the ones with the 23 understanding of local distribution costs. They know 24 where the bottlenecks are. We need them to have some 25 incentive to want to find cost effective solutions on 26 the demand side. 27 I think I have already indicated what we would 28 like to see the Board do here. I would simply close by 147 GREEN ENERGY COALITION, Presentation 1 urging the Board to step back for a moment. I have 2 great sympathy for the Board, that you are faced with 3 what must be a tremendous workload at this time, dealing 4 with all the questions and all the problems and all the 5 mechanical issues associated with changing the former 6 regulation in the province and wrestling with the 7 restructuring sector. 8 But it would be a great shame if the Board 9 became in a sense just an administerer of some kind of 10 mechanized regulatory approach. There are societal 11 benefits, public benefits that we have enjoyed or that 12 we potentially still can enjoy to a greater extent that 13 are not an anathema to competition and economic 14 efficiency. 15 I believe that the Board's proper role is for 16 us to have our cake and eat it too, for us to achieve 17 the benefits of restructuring of competition, yet not 18 throw the baby out with the bathwater, keep the benefits 19 that can be obtained by harnessing the franchise 20 monopolies that exist. Thank you. 21 THE PRESIDING MEMBER: Thank you, Mr. Poch. 22 Does Board staff have any questions? 23 MS KWIK: Yes, please, Mr. Dominy. 24 In Mr. Chernick's comments he referred to some 25 corrections that he thought needed to be made to the IDC 26 that Board staff recommended using. One of the 27 recommendations there was that the value .0062 should be 28 corrected for inflation. 148 GREEN ENERGY COALITION 1 MR. POCH: Yes. I note his comment. 2 MS KWIK: Would the appropriate way of doing 3 that correction be to use the IPI that Dr. Cronin has 4 come up with for the last 10-year period or how would 5 you approach it? 6 MR. POCH: I am going to beg off that. Not 7 being a technical expert on the distinctions between IPI 8 and the various other escalators I know that that's a 9 debate generally in this proceeding. 10 In instructing Mr. Chernick as to what we 11 wanted here, he immediately noted this problem when he 12 reviewed the proposal and was familiar, vaguely familiar 13 with that study from having dealt with it in the past. 14 So I said by all means put a quick appendix in to alert 15 the Board to it, but I didn't invite him to spend any 16 great number of days working out the right number for 17 you or precisely how it should be done, and so I can't 18 really -- 19 MS KWIK: I understand. Thank you. 20 That's all from the Board's staff. 21 THE PRESIDING MEMBER: Dr. Zerker. 22 MEMBER ZERKER: Good afternoon, Mr. Poch. 23 MR. POCH: Good afternoon. 24 MEMBER ZERKER: Let me explore with you a 25 problem that I think you have and I think we have and I 26 personally have because I think we are all interested in 27 energy efficiency. It goes something like this: You 28 have emphasized the supply side with short run marginal 149 GREEN ENERGY COALITION 1 costs with a utility versus long run marginal costs and 2 that's a realistic concern. 3 But if I add to that the demand side and take 4 a look at elasticity of demand I also find that it is 5 even more problematic and it's in this sense. I look 6 back and we don't have any specific examples in 7 electricity as indicative as we have from the oil 8 industry about the effects of massive increases in 9 prices and what it does to consumption. 10 In the oil industry, going back to the first 11 and second price shock, initially that was in 1973 when 12 prices quadrupled almost overnight, demand continued to 13 increase. The rate of demand slowed down, but it took 14 until 1981 before we actually saw a reduction in 15 consumption. So the demand side makes it even more 16 problematic. 17 So what we are saying is that from both the 18 supply and the demand side the economic pressures are 19 such that, yes, I agree with you that it is not 20 inherently manageable within the market, so I agree with 21 you on that. 22 But then I come to a very serious problem from 23 the point of view of the regulator, and that is that as 24 you pointed out to us the regulations that you are 25 making note of -- the requirements for DSM that you are 26 making note of more or less fall on the retailer. You 27 mentioned the retailer a number of times. 28 The distributing company, as distributing 150 GREEN ENERGY COALITION 1 company, doesn't seem or at least I should ask you it 2 does not seem to me to have the kind of DSM potential 3 that you have experienced elsewhere and as you make note 4 of yourself. 5 What are we supposed to do with an unregulated 6 market? I mean, the retailer isn't regulated. The 7 producer of the commodity is not regulated and we aren't 8 going to regulated. In fact, the movement will be in 9 the other direction. 10 MR. POCH: Exactly. 11 MEMBER ZERKER: So I have some serious 12 problems with what the Board ought to do in the part 13 that we have management opportunities. 14 MR. POCH: Let me break down your concerns 15 into two separate questions, if I may. Your first point 16 that there isn't a high price elasticity -- 17 MEMBER ZERKER: The chart ran its variables. 18 MR. POCH: I suggest that the need for DSM is 19 in a sense paramount to the rate design question. I was 20 arguing -- I expressed concerns on behalf of my client 21 about this rate design question about too much being in 22 the fixed charge because they were watering down the 23 signal for conservation and not enough return on capital 24 being calculated, and this is the contribution issue, 25 again because we will be watering down the price signal. 26 Well, your point is that, unfortunately, our 27 price signal doesn't get the response, the perfect 28 response, and we agree that hence -- 151 GREEN ENERGY COALITION 1 MEMBER ZERKER: It is far less than a perfect 2 response. 3 MR. POCH: Hence I would say an even greater 4 need for DSM, for the utility to say, okay, what is -- 5 accounting for all the economics of the situation, what 6 is the rational thing to do here in a choice between a 7 conservation measure and use of more electricity? 8 They are in a position to do that kind of 9 analysis and then to go in and to try to facilitate that 10 DSM occurring. So I would say that that heightens the 11 need for DSM relative to rates, and not to say that rate 12 design doesn't help. It's just a relatively blunt 13 instrument, fair enough. 14 The second point or question you raise is with 15 respect to the fact that we now have a lot of the sector 16 which is unregulated and will be unregulated. Implicit 17 in our position, but maybe I should have been more 18 explicit, is an assumption that whoever is responsible 19 for DSM should be looking at the savings as if it were 20 vertically integrated -- in other words, capturing the 21 savings up and down the line, to decide whether -- I 22 mean the test should be is the customer and society net 23 better off or worse off doing this DSM all costs and all 24 benefits counted. 25 So I think that, yes, the rational approach 26 would take into account all costs and all benefits, 27 whether it's from the regulator or the unregulated 28 sector we have to look at that. 152 GREEN ENERGY COALITION 1 Now, in the gas side in Ontario we have had 2 commodity deregulation for about a decade and the 3 practice is and remains that the gas company in deciding 4 whether a DSM measure is cost effective does count the 5 commodity savings that the customer would enjoy in 6 deciding whether this is an investment that makes sense. 7 It does lead inevitably to the question of how 8 evenly the costs and benefits are borne between 9 different customers, and that is clearly always an issue 10 for designers of DSM programs to try to spread out the 11 benefits, try to make them as universal as possible so 12 no one is just paying and not receiving and so on. 13 But, in any event, Mr. Chernick guesstimated 14 that we are looking at rate impacts, you know, of less 15 than 1 per cent here. 16 Rate impacts have just not become a big 17 concern from DSM, at least on the gas side in Ontario at 18 the scale that it's being conducted, yet we are 19 achieving hundreds of millions of dollars of net 20 benefits. 21 MEMBER ZERKER: Mr. Poch, can you give me an 22 example -- I asked this this morning too -- I want an 23 example, a specific example, of what a distributing 24 company would actually do in the application of a DSM 25 measure. Now, I'm talking about distribution as 26 distribution. 27 MR. POCH: Okay. 28 MEMBER ZERKER: Okay? 153 GREEN ENERGY COALITION 1 MR. POCH: Of course you can't do a 2 conservation measure that just saves distribution costs. 3 You are going to save the electricity commodity costs 4 for the customer as well. 5 MEMBER ZERKER: Right. 6 MR. POCH: And you are going to unburden the 7 transmission system. 8 So let me preface my response by saying I 9 think it is the wrong approach to only look at the 10 distribution savings to decide whether a measure makes 11 sense. 12 MEMBER ZERKER: No. I agree with that, except 13 that I have a problem, as a regulator, of one aspect of 14 the production and delivery system. 15 MR. POCH: But a distributor nevertheless does 16 have this relationship with the customer, has a trust 17 that has been built up, even after we see all these 18 amalgamations that are foretold. 19 I believe that it is reasonable to assume that 20 the distributor will continue to be seen to be a sort of 21 neutral player by the public as opposed to the 22 marketers, the commodity marketers, that will remain 23 particularly well situated to deliver DSM. 24 They have a billing relationship with the 25 customer whether or not they contract that out in the 26 end or not. So they have a very good avenue both to get 27 messages to customers and to obtain contributions from 28 customers or spread the cost amongst a large customer 154 GREEN ENERGY COALITION 1 base if their benefits are broad. 2 And they have a particular interest that is 3 hard for anybody else to assess, that is, the benefits 4 in alleviating and avoiding capital expenses to the 5 distribution system, which of course are very specific 6 to the local situation and even within the local 7 situation. 8 So I think that as distributors they remain 9 excellent candidates for being involved, whether or not 10 others are, certainly for being involved in DSM 11 evaluation and delivery. 12 The actual programs, I can't -- off the top of 13 my head there is any number of programs, from 14 information style programs to working to improve 15 standards, minimum standards. They can be working with 16 retailers to ensure availability of more efficient 17 products. They can be providing valuation services to 18 customers. 19 I know, for example, in the City of Toronto 20 there is the Green Communities Program that goes around 21 and does audits of people's homes and makes suggestions 22 of measures that can be put in place to save 23 electricity, to save gas, to save water, and will also 24 arrange for the job to be done for people; that is, the 25 different utilities, Toronto Hydro and Consumers Gas, in 26 this case, contribute to that program because they 27 recognize that there will be benefits for their 28 customers broadly. The measures are many and varied, 155 GREEN ENERGY COALITION 1 from weatherization to upgrading appliances to setting 2 back thermostats, what have you. 3 MEMBER ZERKER: Okay. Thank you very much on 4 that. 5 Just one question now on your proposal that 6 DSM measures are introduced in a voluntary way in the 7 first phase. 8 MR. POCH: It is not our first choice, but we 9 are trying to be realistic here and understand that you 10 can only do so much. 11 MEMBER ZERKER: My question to you is: How 12 would you suggest the Board entertain that proposal of 13 yours in what manner, I guess for an example, if it was 14 to be included in a Z-factor or what? 15 What did you have in mind? 16 MR. POCH: I think that probably all that is 17 needed is for the Board to say that -- express its 18 concern, if it shares this concern, that the DSM should 19 not be disincented and that for utilities wishing to do 20 DSM, continue or to do DSM, those utilities should 21 include in their application -- 22 MEMBER ZERKER: Part of their costs? As part 23 of their costs? 24 MR. POCH: As part of their costs, but as part 25 of their structuring of their particular rate 26 application of PBR, I may have misinterpreted, but I had 27 understood that the draft PBR Handbook is a sort of 28 default document, but that utilities can propose 156 GREEN ENERGY COALITION 1 deviations where they can justify them to the Board. 2 I am suggesting that the Board make it clear 3 that utilities should feel free to do so in the case of 4 DSM and that -- in which case the utilities can 5 consider -- the Board will consider proposals for the 6 follow through of program costs; that is, the Z-factor, 7 lost revenue adjustments and shared savings -- incentive 8 style incentives. 9 I think the Board should go that far -- 10 although leaving it sort of open to the utilities -- I 11 think the Board may wish to go that far to actually 12 prescribe that an incentive mechanism, as put forward, 13 should be of the shared savings variety, just to avoid 14 having to go through a whole round again of debate about 15 how best to do this. 16 I think the Board has -- and obviously it is 17 up to you to decide, but I think you have enough 18 experience now and enough comfort with that approach 19 that just from a regulatory savings perspective it might 20 be wise to telegraph if you have conclusions as to just 21 where we want to go, just do that at this point. 22 MEMBER ZERKER: Those are my questions. Thank 23 you. 24 THE PRESIDING MEMBER: Thank you, Dr. Zerker. 25 Mr. Vlahos. 26 MEMBER VLAHOS: Thank you, Mr. Chairman. 27 Mr. Poch, just a couple of questions. 28 The term that you have used is that the 157 GREEN ENERGY COALITION 1 approach that is in the PBR Handbook is non-neutral, 2 definitely not progressive and it is in fact regressive. 3 We have heard that there may be a number of 4 utilities, electric utilities, that do have some form of 5 DSM programs. I have no idea what the incentives are, 6 but the programs are there and I have no idea how they 7 compare with -- how comprehensive they are vis-a-vis the 8 gas industry, but I think the book is aggressive in that 9 context. 10 Are you referring to the lost opportunities or 11 are you referring to the same utilities -- sorry, three 12 parts -- the lost opportunities that the utilities who 13 don't have DSM programs would not enter into DSM 14 programs, or utilities who already have DSM programs 15 will abandon them? 16 Which one of the two or is it both? 17 MR. POCH: I think it is both. I think that 18 in the pre-existing regime a utility could at least 19 forecast DSM expenditure. 20 First of all, I should answer your earlier 21 question or puzzlement about what level of DSM. 22 I think it is fair to say, without having 23 studied the matter, that my impression is that it is not 24 widespread and it is not as comprehensive as we see on 25 the gas side. 26 This is kind of a small scale operation in 27 most utilities, although some -- you know, when you get 28 a utility the size of the City of Toronto, it can 158 GREEN ENERGY COALITION 1 nevertheless be not insignificant. 2 But it is not something that most utilities 3 will have been thinking about when they have looked at 4 this PBR proposal and I think certainly it would be 5 healthy to prod them into thinking about it, those that 6 have some programs, before they make their particular 7 application. 8 But in answer to your specific question, yes, 9 I think that it would be a disincentive to those that 10 are really doing DSM. 11 I would certainly not invite anybody who had 12 not been doing to consider doing it because of the loss 13 of the cost passthrough or the actual program expenses. 14 Presumably, they would find it hard to make a return on 15 any investment, and they will see lost revenues. 16 MEMBER VLAHOS: Is your concern mainly with 17 the loss of what already exists as opposed to inviting 18 new entrants into the DSL? 19 MR. POCH: I think the far greater concern is 20 with the lost potential, although it is perhaps 21 particularly upsetting to see something that exists be 22 lost. In terms of the scale of the opportunity, what is 23 being done is perhaps minuscule compared to what could 24 be done. 25 We have been in this kind of purgatory Ontario 26 since the beginning of the decade when the old way of 27 doing things -- everyone realized that those days were 28 gone. We didn't yet have restructuring. We no longer 159 GREEN ENERGY COALITION 1 had this Board's review of Ontario Hydro's spending. 2 Ontario Hydro became a black box. And DSM, which until 3 then had been largely their responsibility, just 4 withered and there was no one to complain to. 5 So we have lost a few years. We have lost 6 momentum and we have lost some expertise. Not that I am 7 defending that the old Hydro's approach was optimal, but 8 I think it was getting benefits that would have been 9 lost for a few years. It would have been nice to start 10 rebuilding that capability but within this new paradigm 11 of competition and so on. 12 I should say some have levelled criticism at 13 the old Ontario Hydro DSM plan as having led to stranded 14 investment, wasted investment. Perhaps this is trite 15 for the Board, but it was an investment in its day that 16 was cheaper than the alternative, which would have been 17 another Darlington, or what have you. 18 So while it may not have been all cost 19 effective, because their load forecast was wrong and we 20 were there saying it was wrong too, it was the lesser of 21 evils. No one has a perfect crystal ball. That is all 22 one can ask. 23 MEMBER VLAHOS: If we can remove ourselves for 24 a minute from the idea, at least from the GEC's 25 perspective as to what you have, can we talk about 26 second-best solution. 27 MR. POCH: Sure. 28 MEMBER VLAHOS: Your concern is that the 160 GREEN ENERGY COALITION 1 systems which are already offering some kind of DSM 2 programs -- which, by the way, the costs are already 3 included in rates. 4 MR. POCH: Yes, the forecast costs. 5 MEMBER VLAHOS: May be first rated by 6 management or whatever. You don't have to do that but 7 it is going to enhance the bottom line, so why don't we 8 just drop it. 9 Again, as a second-best solution, can you see 10 anything that the Board can do to force those utilities 11 to continue with at least the level of expenditure that 12 has been going on for the last year or the year before, 13 or you find the period. 14 MR. POCH: Yes. Conceivably, you could 15 construct an SQI, a service quality indicator, that 16 insisted that the utility's current delivery of 17 conservation not be reduced. You have an information 18 problem. 19 MEMBER VLAHOS: That was my next question. 20 MR. POCH: The experience on the gas side -- 21 we had Consumers Gas delivering DSM for four years and 22 each year they didn't meet their previous year's target 23 for DSM. Then we put in place an SSM, and this year 24 they are over target for DSM. 25 When they have the carrot, they get much more 26 creative, more cost effective, and everybody wins. 27 We are sold on the incentive regulatory 28 structure for DSM. I understand you to preface your 161 GREEN ENERGY COALITION 1 question, which is: Maybe if we can't have it today, 2 are there some stop-gap measures? 3 I would think the most important thing would 4 be for the Board to enunciate where it wants to consider 5 going in that direction and to keep that, not to lose 6 momentum towards incentive regulation of DSM. 7 I think the invitation for utilities to do so, 8 which frankly is likely to have only slight effect, I 9 grant that; it is only likely one or two utilities that 10 are going to seize that opportunity. I think that would 11 maintain some momentum or maybe build some momentum, 12 maybe give us a little bit of learning by doing, but 13 send a nice clear signal to others that they need to 14 start thinking about it. 15 That is what we saw as a kind of placeholder 16 interim step. 17 Certainly, I think a similar complimentary 18 step the Board could consider would be the explicit 19 enunciation that this is a topic for the interim review 20 and that parties should be thinking about how best it be 21 accomplished. 22 MEMBER VLAHOS: You spoke of information 23 deficiencies, as to who carried DSM programs. Does that 24 come from specific knowledge from discussions in the 25 task forces, or is it -- 26 MR. POCH: No. I just meant you were going to 27 be completely reliant on utilities. If we in the Draft 28 Handbook say one service quality indicator is that 162 GREEN ENERGY COALITION 1 utilities must demonstrate they haven't reduced their 2 commitment to DSM, we don't even know who the ones they 3 have committed it to are. 4 It's kind of scout's honour situation, which 5 may be -- 6 MEMBER VLAHOS: That's what I wanted to 7 confirm; that definitely we don't have information as to 8 what systems offer DSM. 9 MR. POCH: That's right. We have no good 10 database here. 11 MEMBER VLAHOS: Staff would confirm that? 12 Mr. Poch sounds very definitive. 13 MR. POCH: It's true, I haven't studied the 14 matter. But I am unaware of any kind of collection of 15 that information. 16 MS KWIK: I know there are some programs that 17 were highlighted in the past in the submissions of the 18 utilities to Ontario Hydro, and we have inherited those 19 files. But I think it would be a lot of work to go 20 through them. 21 For instance, water heater rental discount 22 base and load control. Those kinds of programs would be 23 a bit more obvious to get out of the files. 24 I am not sure that we could get all of the 25 activities from those files. 26 MR. POCH: My understanding is that the load 27 shifting, peak shifting, activities, water heater 28 activities, are probably the largest single activity, 163 GREEN ENERGY COALITION 1 with some utilities being extremely active, I recall. 2 But this is all anecdotal. 3 MEMBER VLAHOS: Thank you. 4 Mr. Poch, just going to the discussion of the 5 IDC, I guess I see a double-edged sword here. 6 Everything else being equal, you want to see a high IDC 7 because of the theoretical conservation possibility. 8 If you don't have a DSM program in place, 9 though -- I'm sorry, I should say no DSM incentives, 10 then doesn't a higher IDC work to the disbenefit of 11 conservation? 12 MR. POCH: In the sense that there is more 13 lost revenue. 14 MEMBER VLAHOS: Yes. So the utility says: 15 Why should I do that? I am going to lose $1 per unit. 16 If it is a low IDC, I lose no dollars per unit. 17 MR. POCH: Yes, I think that is a valid point. 18 I agree that that would be the way that would go. I 19 think it has to be, in that sense, a bit of a package. 20 If we have some kind of lost revenue adjustment 21 mechanism, then that concern is alleviated. 22 MEMBER VLAHOS: So from the PBR Handbook 23 perspective, which deals with all utilities, it does not 24 allow -- I'm sorry, let me rephrase that. 25 The IDC that is in the Handbook is a default 26 IDC, if you like. Then you can say the benefit, from a 27 conservation perspective, of the IDC should be as low as 28 possible and therefore Mr. Chernick's recommendation may 164 GREEN ENERGY COALITION 1 not be to the best of -- may not necessarily meet your 2 client's concerns. 3 MR. POCH: I take your point that if we have a 4 higher IDC, the utility has an even greater lost revenue 5 concern if it engages in conservation, assuming that 6 they don't have a relief valve to turn to, of an LRAM, 7 or some such mechanism. 8 I would suggest, again, just based on actual 9 evidence, that the extent of conservation activity by 10 utilities is so small right now that the larger term 11 would be the impact that this will have on customers. 12 I would assume that consumer conservation 13 efforts would dwarf utility conservation efforts at this 14 point in time, and maybe they always will. I think 15 probably a dominant concern should be to enhance good 16 decision-making by consumers first. 17 While I readily acknowledge your point, I 18 think the dominant concern should remain that the 19 conservation price signal not be inappropriately 20 diminished. 21 MEMBER VLAHOS: From your involvement -- and 22 this is my last question -- in the discussions over the 23 last several months, have you seen any data or any 24 analysis as to if you were to change the IDC by X, say 25 double it, what would translate to a reduction in the 26 fixed charge? 27 Have those numbers been passed around? 28 MR. POCH: I think the gentleman from FOCA 165 GREEN ENERGY COALITION 1 could probably give you that to three decimal points. 2 These are of course -- because we are only dealing with 3 distribution costs, just a portion of the 8 cents per 4 kilowatt hour that the rolled in rates are now, one 5 assumes that we are looking at -- if two cents is 6 distribution, we are looking at where one cent of that 7 is going to get collected. Is it in the end block or is 8 it in the first block? 9 I think it is that order of magnitude, but I 10 understand Mr. McGee is very familiar with these numbers 11 and can probably give you some better perspective on 12 that. 13 MEMBER VLAHOS: Thank you, Mr. Poch; thank 14 you, Mr. Chairman. 15 THE PRESIDING MEMBER: Mr. Poch, I just have 16 one quick question. 17 Mr. Chernick did work and he talked about 18 Vermont. Vermont is on what sort of rate setting? 19 MR. POCH: It's traditional cost of service. 20 THE PRESIDING MEMBER: Are you aware of any 21 jurisdiction which has gone into PBR which has 22 introduced some form of DSM incentive arrangement? 23 I ask that to see what other jurisdictions may 24 have done in this regard. 25 MR. POCH: I have a particularly bad memory 26 for that sort of database. I recall seeing a document I 27 filed with the Board in the context of the standard 28 service discussion, which was a matrix that Americans 166 GREEN ENERGY COALITION 1 had produced some few years ago of what was going on. 2 I will certainly have a look to see if there 3 is anything in the public record that I can include for 4 you in our written submissions. 5 I know that England, for example, has been, 6 with a few shifts of gears, looking at this problem. I 7 believe there is an Energy Conservation Office in 8 England. 9 Certainly there was the systems benefit charge 10 in California as part of restructuring, which I think 11 was -- there I think it was intended as a temporary 12 measure. I am not sure. 13 Massachusetts I know was talking about a 14 systems benefit charge. I don't know exactly what has 15 happened with those systems benefit charges; that is, 16 how they go about spending the money. But I can 17 probably fairly easily put my hands on some information, 18 and I will try to append that to a written submission 19 for you. 20 THE PRESIDING MEMBER: That will be helpful, 21 Mr. Poch. That would certainly give us an idea of how 22 other people have tackled this. 23 MR. POCH: Yes. 24 THE PRESIDING MEMBER: Do Board staff have any 25 concluding questions? 26 MS KWIK: No, we don't; thank you, Mr. Chair. 27 THE PRESIDING MEMBER: Mr. Poch, thank you 28 very much for coming forward and sharing with us your 167 GREEN ENERGY COALITION 1 understanding and suggestions. 2 MR. POCH: Thank you. 3 THE PRESIDING MEMBER: Board staff, tomorrow 4 we start at 9 o'clock with...? 5 MS KWIK: Yes, with VECC. 6 THE PRESIDING MEMBER: Vulnerable Energy 7 Consumers Coalition. Is that right? 8 MS KWIK: Yes. 9 THE PRESIDING MEMBER: So we will meet again 10 tomorrow morning at 9 o'clock. 11 Thank you, everybody. 12 --- Whereupon the hearing adjourned at 1455, 13 to resume on Tuesday, October 5, 1999 at 0900 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 168 1 INDEX 2 PAGE 3 Hearing commenced at 0907 4 4 Comments by Ms Kwik 5 5 Presentation by Mr. Rodger, Mr. Zebrowski 14 6 and Ms Tam on behalf of Toronto Hydro 7 Questions by the Board 22 8 Presentation by Mr. Klippenstein and 55 9 Mr. Gibbons on behalf of Pollution Probe 10 Questions by Board staff 68 11 Questions by the Board 69 12 Upon recessing at 1129 86 13 Upon resuming at 1148 87 14 Presentation by Mr. Mia, Mr. Frey, Mr. Wilkie, 87 15 Mr. Sanford and Mr. MacKenzie on behalf of 16 the Coalition of Distribution Utilities 17 Questions by Board staff 100 18 Questions by the Board 101 19 Luncheon recess at 1255 128 20 Upon resuming at 1350 128 21 Presentation by Mr. Poch on behalf of 128 22 Green Energy Coalition 23 Questions by Board staff 147 24 Questions by the Board 148 25 Hearing adjourned at 1455 167 26 27 28 169 1 UNDERTAKINGS 2 3 NO. DESCRIPTION PAGE 4 1.1 Toronto Hydro to do an assessment of 42 5 what would be the impact on Toronto 6 Hydro's total revenue requirement and 7 the impact on the return on common 8 equity if the default total factor 9 productivity was changed by 1 per cent 10 11 1.2 Coalition of PUCs to ascertain if 102 12 there were any gaps in Appendix A with 13 respect to the street lighting 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28