735 1 RP-1999-0034 2 3 4 IN THE MATTER OF ss. 19(4), 57, 70 and 78 of the 5 Ontario Energy Board Act, 1998, S.O. 1998, c. 15, 6 Sched. B; 7 8 9 AND IN THE MATTER OF an Ontario Energy Board 10 Staff proposed Electricity Distribution Performance 11 Based Regulation Handbook 12 13 14 Hearing held at: 15 2300 Yonge Street, 25th Floor, Hearing Room No. 1, 16 Toronto, Ontario on Friday, September 24, 1999, 17 commencing at 0903 18 19 20 21 22 23 TECHNICAL CONFERENCE 24 25 VOLUME 4 26 27 28 736 1 APPEARANCES 2 JENNIFER LEA/ Board Counsel, Board 3 MIKE LYLE 4 ROBERT WARREN Consumers' Association of 5 Canada 6 ROBERT POWER/ Hydro Mississauga, London 7 SEABRON ADAMSON/ Hydro, Oshawa PUC, Sarnia 8 ALEXANDER GRIEVE Hydro, St. Catherines Hydro, 9 Whitby Hydro, Petrolia PUC, 10 St. Thomas PUC, GPU Electric 11 Inc./GPU Services Inc. and 12 Collingwood PUC, ENERConnect 13 JACK GIBBONS Pollution Probe 14 PAUL FERGUSON/ Upper Canada Energy 15 DR. C.K. WOO/ Alliance 16 PETER FAYE/ 17 DAVID WILLS 18 MARK RODGER Toronto Hydro 19 RICHARD STEPHENSON Power Workers Union 20 DAVID POCH Green Energy Coalition 21 ELISABETH DEMARCO Lindsay Hydro, Flamborough 22 ZIYAAD MIA Coalition of Distribution 23 Utilities 24 ROGER WHITE ECMI 25 TOM ADAMS Energy Probe 26 MAURICE TUCCI MEA 27 STEPHEN CARTWRIGHT Enbridge Consumers Gas 28 BILL HARPER Ontario Hydro Networks 737 1 APPEARANCES (Cont'd) 2 KEVIN BELL Great Lakes Power 3 GERRY DUPONT Nepean Hydro 4 RICHARD BATTISTA Union Gas Limited 5 BRIAN McKERLIE Municipality of Chatham-Kent 6 MICHAEL JANIGAN Vulnerable Energy Consumers 7 Coalition 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 738 1 Toronto, Ontario 2 --- Upon resuming on Friday, September 24, 1999, 3 at 0903 4 MS LEA: Good morning. Something 5 unexpected has no doubt detained one of our usually 6 extremely reliable court reporters, so we hope he is 7 all right. 8 In the meantime we will proceed. I 9 would ask, though, because we have only one court 10 reporter with us to enunciate clearly, speak slowly, do 11 everything you can to ensure that your words are 12 clearly heard on the record. 13 Now, with us this morning we have a 14 gentleman from the Ontario Federation of Agriculture. 15 I wonder, sir, if you could introduce yourself and 16 spell your name and please give us your presentation? 17 TED COWAN 18 PRESENTATION 19 MR. COWAN: I am Ted Cowan. That is 20 C-O-W-A-N and I am here as a representative of the 21 Ontario Federation of Agriculture. 22 I intend to proceed in three steps. 23 I will set out the farm context so you know what 24 farmers are facing. I will set out a summary of the 25 OFA views on aspects of the PBR Handbook, and these 26 views are meant to proceed some understanding and 27 guidance towards changes that OFA and farmers generally 28 would view as improvements. As this is a summary, I 739 OFA Panel 1 will spare you any further recapitulation, and three, 2 at the conclusion I will try to respond to any 3 questions. 4 First, the farm context. 5 Energy costs Ontario farmers a half 6 billion dollars a year. It is our number two cost. 7 Electricity is half of that. Low cost reliable 8 electricity is a key reason Ontario enjoys food that 9 costs half of what it does in Europe and less than in 10 most U.S. cities. It is the foundation of our 11 competitiveness and we don't want to lose that edge. 12 The average age of Ontario farmers is 13 55. About 30 per cent of these farmers will be 14 retiring in the next 10 years. This transition comes 15 at the same time as they face the change to a new 16 energy market. These new farmers who are coming in 17 will face higher costs as they take on debt, have 18 families and buy equipment. Energy costs will be a 19 hand on the balance that determines their future. If 20 electricity prices fall this will help them stay 21 competitive and make the transition. If energy prices 22 rise overall competitiveness in farming in all other 23 sectors will fall and fewer young farmers will make the 24 grade. 25 Few industries in Ontario are as 26 diverse as agriculture and so dependent on energy. The 27 OEB cannot look at every sector to see whether they are 28 doing the right thing. The OFA suggests that the OEB 740 OFA Panel 1 use agriculture as an indicator. The OEB can be 2 certain, absolutely certain, that if agriculture fares 3 well under the new system of prices and regulation then 4 all of Ontario will do as well or better. 5 As the PBR Handbook stands it is our 6 rough estimate that about one-third of farmers would 7 see increases of 15 per cent plus in their total power 8 bills, one-third would see smaller increases and 9 one-third would enjoy reductions in power costs. This 10 is roughly in proportion to their energy use but also 11 perhaps dependent on their locations. 12 The deregulation of power was meant 13 to benefit all Ontario, not just LDC owners and some 14 consumers. Farmers are not LDC owners. For the 15 900,000 OHSC customers there will be no ownership 16 benefit. They will be making a disproportionate 17 contribution to reduce the old Ontario Hydro debt. For 18 the rest of Ontario residents we expect that they want 19 to see the benefits of power deregulation in their 20 electricity bills, not in their arena roof or the 21 quality of carpet in the PUC office. With this 22 distribution proposal electricity rates may be going 23 down but we fear that bills are going up without any 24 short term or long term compensating benefit. 25 Now, we will move to some of the 26 specifics. The first specific, and this is a recent 27 note and not in the hand-out text, deals with price 28 effects. 741 OFA Panel 1 For people with choices, higher 2 service charges may force a choice between gas and 3 electricity. This is a simple function. Do you go to 4 a bar with a service charge and beer at $1 a glass or 5 do you go to a bar where it is $2 a glass but no 6 service charge? If the service charge is $10 your 7 break-even point is 20 glasses of beer. We don't want 8 people getting power drunk. 9 Higher service charges in round 10 numbers on a beef farm, and that is the kind of farming 11 I know about, based on what I have heard so far would 12 go up by $100 to $150 per year on a regular farm 13 service. This is the net on 600 to 900 bales of hay. 14 Now, at 600 bales of hay, every year you start in your 15 haying and you are putting the hay in the mound, 600 16 bales you are near the end of the first day and you are 17 tired and angry. You really don't want people to be 18 equating tired and angry with this price increase if 19 that is what it turns out to be. What does that cost 20 in land? At least one extra acre in the most 21 productive areas of Ontario that goes to the three to 22 five acres that are already working to pay for 23 electricity bills. 24 These new service charges will force 25 customers to be more efficient. There is no doubt 26 about that. If they are going to survive they are 27 going to have to be more efficient. But the purpose of 28 them is to force the LDCs to be more efficient. We 742 OFA Panel 1 just don't see that it is going to cut both ways. 2 Okay. Further remarks. 3 Decentralized regulation. The OFA 4 does not believe that centralized regulation is needed 5 or that it would be an improvement. There is no 6 evidence in our mind that has been put forward 7 indicating that rate regulation is needed. In lieu of 8 centralized regulation the OFA proposes that the OEB 9 recommend to the government that distribution rates be 10 approved by municipal by-law and that distributors and 11 customers have the right to appeal to the OEB. In this 12 formula we would not do away with PBR but we would make 13 it essentially voluntary at the discretion of the local 14 councils and the LDCs. If the LDC were to be 15 privatized then we would suggest that some sort of PBR 16 be mandatory and to govern the relationship between the 17 council and the LDC. 18 Capacity to regulate. The OFA feels 19 that the approach outlined in the draft handbook would 20 lead Ontario into a regulatory morass. With 230 or 250 21 LDCs we believe the OEB would be overcome by the number 22 of rate reviews and the detail in each. Despite their 23 very best efforts, and we have no doubt that they would 24 really try, in time Ontario consumers would lose as the 25 OEB just couldn't keep up. 26 So we feel that changing the 27 legislation to allow the municipalities to approve 28 distribution rates and aspects of service standards and 743 OFA Panel 1 service incentives would provide local control of 2 things that vary locally and are understood locally and 3 where the consequences of error would be borne locally 4 and corrected locally. This would build on the 5 strengths of the past system rather than moving to an 6 untested and more costly system. 7 With respect to the guaranteed rates 8 of return, we call it a guaranteed rate of return 9 though others might call it a regulated rate or return, 10 we would admit to being in some error here in the past. 11 The OFA believes a regulated rate of return for 12 distributors will become a guaranteed rate of return. 13 It will be construed that way very quickly in that it 14 will distort decisions and inflate costs. LDCs will be 15 able to earn about 8 1/2 per cent without meeting 16 targets. The guaranteed rate then is 8 1/2 per cent, 17 not the 9 3/4. The OFA believes that with local rate 18 setting there is no need for a regulated or guaranteed 19 rate of return. 20 If there must be an assured rate of 21 return it should be lower than the historical rates of 22 return. We see no reason to guarantee more than has 23 been made in the past. If there is to be an assured 24 rate we think less than 3 per cent. If there is to be 25 a cap the cap should be approximately the rate of 26 inflation plus about 4 per cent. 27 Previous technical and efficiency 28 improvements were achieved with rate freezes and no 744 OFA Panel 1 assured rate of return. This is the climate that 2 farmers work in. We have no assured rate of return and 3 we don't have rate freezes. We have had declining 4 prices for years and years and years since 1976. 5 Again, with beef farmers, which I 6 know a bit about, we have had to make efficiency 7 improvements to compensate for the fact that beef 8 prices have gone from $1.05 to 80 cents while at the 9 same time the non-farm input costs have been rising at 10 least at the rate of inflation. Beef farmers have made 11 those changes and many are doing all right in spite of 12 the lower prices and the higher costs. So if you want 13 to improve efficiency you get it by taxing and reducing 14 incomes, not by increasing or guaranteeing incomes. 15 The Royal Family might be a good 16 example. They have a guaranteed income and they are 17 not necessarily more efficient than they used to be. 18 The 9.75 is a high road to indolence 19 and apathy for LDCs, and that is a very sad comment to 20 have to make because we believe they have been very 21 good up to this point. I would hate to see them put on 22 that path. 23 The 9.75 is also an assured source of 24 inflation. It rewards firms who do nothing to earn it. 25 There would be no improvements for customers assured 26 out of the 9.75, or out of the 8.5, if that is the true 27 guaranteed rate. All of the increase then would be 28 inflation. It would be a tragic step in undoing the 745 OFA Panel 1 economic sacrifices made by people for the past eight 2 to ten years to bring inflation under control. And 3 those are not small sacrifices that Canadians have 4 made. 5 They had essentially frozen incomes. 6 They had to learn to make do with less. Hundreds of 7 thousands of them have switched jobs, not voluntarily, 8 because of it. 9 So on a net present value basis, 10 then, the payback for consumers of this approach is 11 likely to be 25-plus years, and that's as close to 12 never as you can get. 13 What should be regulated, in the 14 OFA's view? 15 The OFA believes that 16 performance-based regulation for items such as line 17 locates that are price sensitive or amenable to change 18 by customers can best be achieved by using rate 19 approvals by local councils. For items crucial to 20 performance, such as emergency response standards, for 21 rates based on use rather than connections, the OFA 22 believes that distributors should meet specific 23 locale-sensitive requirements as part of their 24 qualifying for an OEB licence. They don't think that 25 the emergency kinds of things should be anything but 26 very specifically pinned down. 27 As a general principle, no producer 28 or distributor should be allowed to cause such 746 OFA Panel 1 widespread externalities as stray voltage without being 2 answerable for the consequences. The OFA believes that 3 the OEB should require distributors to monitor tingle 4 or stray voltage in barns and to correct tingle voltage 5 problems in barns when the wiring meets the code and 6 where tingle voltage exceeds the 0.5 volts on a 7 recurring basis. 8 What costs should be used as the base 9 for rates of return? This is the retained earnings 10 versus the contributed costs question and our views on 11 it. 12 PUCs purchase their assets using 13 their funds from rates and using funds contributed by 14 beneficiaries. The mix varied from place to place. 15 OFA views an asset that was purchased with a 16 contribution to be the same as an asset purchased with 17 funds from rates. 18 If there is to be a rate of return on 19 these assets, it should be the same. 20 However, the majority of assets of 21 PUCs and of OHSC were paid for by people now retired or 22 deceased and provided to us on the basis that those 23 assets be available on a not-for-profit basis. We 24 believe we should respect that proviso. If we care to 25 earn a profit from assets we have bought ourselves, 26 that is okay; but to treat the LDC endowment as 27 something we should profit from is a breach of an 28 understanding, which we undertook implicitly when we 747 OFA Panel 1 accepted the gift. 2 Moreover, apart from cash balances, 3 as the endowment consists of sunk costs, managing these 4 existing assets for a rate of return will not make our 5 future investments more efficient. It will simply 6 monetize an asset in an inflationary manner. 7 Continued OHSC ownership. The OFA 8 endorses a position that OHSC continue to own and 9 operate the rural distribution service. If there are 10 to be sales of parts of the OHSC distribution network, 11 the OFA asks that customers be consulted and given some 12 powers parallel to those of urban electors. 13 Rural rate assistance. Rural 14 residents in areas where power would cost more than 115 15 per cent of the provincial average benefit from rural 16 rate assistance now. We have been assured that rural 17 rate assistance will be continued in a form modified to 18 suit the changing market. OFA proposes that the 19 present whole price of electricity for RRA 20 beneficiaries -- presently about $1,100 for 12,500 21 kilowatts per year -- be indexed to the standard supply 22 price, plus distribution and transmission charges; that 23 is, the new whole price. 24 The new RRA would kick in when the 25 new whole price exceeded the $1,100 threshold for 26 12,500 kilowatt hours. With proper distribution costs, 27 the RRA requirement, presently about 140 million per 28 year, could fall. The OFA proposes that the savings be 748 OFA Panel 1 directed towards underwriting aids to construction for 2 rural gas line extension. This transfer of funds would 3 bring more energy competition to rural Ontario and 4 accelerate the RRA savings as more rural residents 5 could use gas for heat. 6 The RRA tax requirement could be 7 reasonably expected to fall if electric distribution 8 costs are well controlled. 9 The rural rate assistance could 10 potentially then be used by the OEB as a simple 11 indicator of what is happening to distribution costs in 12 much of Ontario, and this in turn will provide it with 13 a measure of how LDCs ought to be doing and, at the 14 same time it will bring greater competition to the 15 energy market in Ontario. 16 That is my conclusion. I am happy to 17 take any questions at this time. 18 MS LEA: Thank you very much, Mr. 19 Cowan. 20 Before we do, that, I wonder if it 21 would be agreeable to you to have the summary statement 22 that you provided marked as an exhibit in these 23 proceedings? 24 MR. COWAN: I can't think of any 25 reason why not. 26 MS LEA: Thank you very much. 27 I think we are at "E", so this will 28 be Exhibit E, please. 749 OFA Panel 1 EXHIBIT NO. E: OFA summary 2 statement 3 MS LEA: Can I ask who has questions 4 for Mr. Cowan? 5 Mr. Rodger. 6 MR. RODGER: Thank you, Ms Lea. Good 7 morning, Mr. Cowan. 8 MR. COWAN: Good morning. 9 MR. RODGER: I just want to make sure 10 I understand your position on one of the issues with 11 respect to the rate of return, the level of rates and 12 the municipality's role in that. 13 Are you aware, sir, that under the 14 Energy Competition Act, 1998, the province has 15 essentially declared that the municipalities are the 16 shareholders of municipal electric utilities? 17 MR. COWAN: That is certainly true 18 for the municipal electric utilities. For the OHSC, 19 which serves virtually all farms, the province is the 20 shareholder. 21 MR. RODGER: For those communities 22 where municipalities are involved, would it be fair to 23 conclude that the local municipal council is really the 24 representative of the shareholders; that is, the people 25 of the community generally? 26 MR. COWAN: That's right. They are 27 the owner, and we are of the view that owners should be 28 able to set the price of the things they sell. 750 OFA Panel 1 MR. RODGER: Are you aware that under 2 the proposal that Board staff has put forward on this 3 draft PBR Handbook, that is essentially what happens; 4 that local councils can direct the boards of directors 5 of their new companies as to what level of rates and 6 what level of application of rate of return it should 7 be seeking from the Energy Board? 8 MR. COWAN: That rate, though, as I 9 understood, is conditional on the OEB approval. Our 10 point of view would be that they had set their own 11 rate, and if the LDC or the customers, significant 12 groups of customers objected, they could appeal to the 13 OEB and that there would be no need to go to the OEB, 14 barring the need for an appeal. 15 MR. RODGER: From your comments I saw 16 a bit of a parallel between what you are proposing and 17 what the Board is proposing, and that is the sense that 18 even under the Board's proposal, there is this local 19 discretion over rate and that those local communities 20 would be in the best position to propose the rates for 21 the Board's consideration. 22 MR. COWAN: Within the handbook we 23 didn't have a sense of local discretion. That may have 24 just been a misreading on our part, but nonetheless 25 that was the way we read it. 26 MR. RODGER: I appreciate that. 27 Thank you, sir; those are my questions. 28 MS LEA: Thank you, Mr. Rodger. 751 OFA Panel 1 Who else? 2 I think Mr. White had questions. Is 3 that correct? And Dr. Cronin also. 4 MR. WHITE: I would like to fully 5 understand how your scheme with respect to rural rate 6 assistance would work. 7 Could you go back and recap that 8 again for me? Perhaps in different words I might 9 understand it better. 10 MR. COWAN: The way it works now is 11 that any rural resident in the Ontario Hydro Services 12 Company distribution area who would otherwise be paying 13 more than 115 per cent of the provincial average for 14 residential power is given a reduction in their service 15 rate so that it brings their price down to 115 per cent 16 of the average. 17 That works out currently to 18 approximately $1,100 for the first 12,500 kilowatts of 19 power a year. 20 We would propose that whatever 21 happens to the standard supply price and whatever 22 happens to distribution and transmission prices, when 23 these things are added up, if that comes to more than 24 $1,100 for a particular customer for that 12,500 25 kilowatts, the rural rate assistance would bring things 26 back down to that price level. 27 If it worked out to less than that, 28 then the rural rate assistance for those customers 752 OFA Panel 1 would not be needed. It would still be available if it 2 should become needed in the future; but at that point, 3 it would not be paying out. 4 It is our belief that power cost, the 5 actual generation costs, are supposed to come down. It 6 is our hope that distribution and transmissions costs 7 come down and that we would like to see the savings in 8 rural rate assistance redirected to make energy choices 9 more broadly available in rural Ontario. Whereas 10 almost 95 per cent of urban and town residents in 11 Ontario have access to gas, less than 30 per cent of 12 rural residents have access to gas. 13 We would like to see that increase. 14 We believe that they would switch from electric heating 15 or would heating to gas heating. They would reduce the 16 call on the rural rate assistance and energy 17 competition would exist in an even more substantive way 18 in most parts of Ontario. I believe that would be good 19 for industrial development in rural areas and we 20 believe it would be good for consumers in rural areas 21 with no harm -- no additional cost to anybody else. 22 MR. WHITE: Have you a sense of the 23 number of farms that currently receive rural rate 24 assistance in Ontario? 25 MR. COWAN: I'm just trying to recall 26 the numbers, but I believe that of farms approximately 27 23,000 farm accounts get rural rate assistance out of 28 approximately 90,000 accounts on rural rate assistance, 753 OFA Panel 1 but I would be subject to correction on that. I think 2 I'm in the ballpark. 3 MR. WHITE: Are you aware that some 4 200,000 residential accounts receive rural rate 5 assistance? 6 MR. COWAN: Okay. That doesn't seem 7 completely unreasonable. But as there are only what we 8 would say 68,000 commercial farms in Ontario, they 9 can't -- all of those 200,000 are not farmers. Most 10 people on rural rate assistance are rural residents, 11 possibly retired farmers, urbanites who have moved out 12 to the country, whatever. 13 I would just point there, Mr. White, 14 the history of rural rate assistance. Since 1983, the 15 cost has gone from about $23 million to $140 million. 16 We think that is largely indicative of people moving to 17 the country, not -- because the number of farmers has 18 in fact decreased substantially in that time period. 19 MR. WHITE: I'm not convinced that 20 that is a fact. In fact, when you look at the number 21 of customers receiving rural rate assistance today, in 22 fact it is a lower number than were receiving it in 23 1983. 24 MR. COWAN: I don't have past 25 customer numbers, just their revenues. 26 MR. WHITE: All right. Thank you 27 very much for your comments. 28 MS LEA: Thank you, Mr. White. 754 OFA Panel 1 Anyone else besides Dr. Cronin? 2 Oh, pardon me. I didn't see you, 3 Mr. Grieve. Please go ahead. 4 MR. GRIEVE: I just had a couple of 5 quick questions. 6 You have implored us to listen to 7 deceased and retired people who have paid into the 8 creation of the system with respect to the treatment of 9 contributed capital. Do we know what these individuals 10 would instruct us if they were told that governments 11 were considering the equivalent of selling off the 12 family silver which they had contributed to, but now we 13 are maybe told that they should sell it off at no cost? 14 MR. COWAN: Sell it off at no cost? 15 MR. GRIEVE: Yes. 16 MR. COWAN: Do you mean at no revenue 17 for the sale? 18 MR. GRIEVE: They were told the 19 family silver prior to sale would be valued at zero. 20 --- Pause 21 MR. COWAN: With respect to the sale 22 of these assets, the tentative view of OFA would be 23 that if there is to be a sale of OHSC assets, 24 distribution assets, then rural municipalities should 25 be given the first crack at assuming the proportionate 26 part of the debt for those assets and paying some 27 nominal fee or amount in return for those, or assume 28 the debt, pay something and then start running if they 755 OFA Panel 1 can or hire someone to run it for them. 2 There is partly a great deal of 3 emotional alarm and partly great deal of business alarm 4 with respect to the prospect of selling LDCs and OHSC 5 assets. It's not something that any of us clearly 6 understand and we don't want to enter into it before we 7 understand it. So it is a sense of rush as much as 8 anything that bothers people. Then there is also the 9 sense that it is just inflationary to start putting a 10 dollar value on things that you are using quite happily 11 and you won't be making any other decisions incumbent 12 on what the dollar value is. 13 The new investment doesn't depend on 14 what you value the present assets at. The new 15 investment can be made quite rationally, perhaps more 16 rationally with market incentives, but it is not 17 necessarily clear that we will be looking at great 18 efficiency gains because of this. 19 I'm wandering on there. I don't know 20 that I have answered your question. Have I? 21 MR. GRIEVE: That is helpful. 22 Do we know what these individuals 23 would instruct us if we were able to consult them and 24 ask them if -- that we had been informed by the Royal 25 Commission that introducing commercialized 26 decision-making would incentivize efficiency in our use 27 of electricity and in our allocations of resources 28 within this industry? 756 OFA Panel 1 MR. COWAN: On the farm efficiency is 2 a pretty important byword. Doing things well, staying 3 competitive is pretty important. 4 Within the community efficiency is 5 not the most important thing to farmers. Keeping the 6 community stable and going is more important. 7 There is a bit of a division as to 8 whether or not they should view these assets as 9 business assets or community assets. For the most 10 part, I find that farmers view them as community assets 11 and they should be used wisely but used for the 12 community benefit. That community benefit includes the 13 businesses and everything in the community, they feel 14 that that is the reason for them having been built, so 15 that they don't see a need to apply business principles 16 to every aspect of their life. Whether the line is a 17 clear line and the proper line is open to question, but 18 they believe there is a line there somewhere in that we 19 are pushing past it in this instance. 20 MR. GRIEVE: Right. I guess in the 21 land of subsidies and marketing boards there is a 22 certain tradeoff between community values and -- 23 MR. COWAN: Which land are we 24 thinking about? England or France or Germany? 25 MR. GRIEVE: No question we are 26 not -- 27 MR. COWAN: Canadian subsidies in 28 farm agriculture, to get this straight, are about 757 OFA Panel 1 7.5 per cent of total farm production compared to over 2 30 per cent in the United States and over 54 per cent 3 in Britain. That is what we are competing against and 4 we think we are doing all right. 5 MR. GRIEVE: There is no question we 6 have a wonderful and efficient system. 7 I guess the short answer, though, to 8 my question of whether we can consult these people who 9 had paid in and created these assets is no, though, 10 isn't it? 11 MR. COWAN: I'm sorry? 12 MR. GRIEVE: The short answer to my 13 question of whether we can contribute or whether we can 14 consult at this time with these people who are now 15 deceased on whether the condition of their contribution 16 to the creation of these assets was exclusively public 17 ownership or if they could consider the realities of 18 1999 is no, though, isn't it? We can't go back there. 19 MR. COWAN: We can read what was 20 written Sir Adam Beck and Earl Snider when they founded 21 Ontario Hydro. That is still on the record. 22 MR. GRIEVE: No question. But they 23 didn't have the Macdonald Commission report before 24 them, though, did they? 25 MR. COWAN: No. They didn't have too 26 many reports. They did have a couple of reports, as I 27 recall. 28 I think we are stretching our level 758 OFA Panel 1 of wisdom if we think we are making better decisions 2 now than they made then and better decisions for our 3 immediate future than they made then for our long-term 4 future. 5 MR. GRIEVE: Thank you. 6 MR. COWAN: There is no reason to 7 doubt what they have provided us so far. 8 MS LEA: Anything further, Mr. 9 Grieve? 10 MR. GRIEVE: No. That's fine. Thank 11 you. 12 MS LEA: Thank you. 13 Mr. Mia? 14 MR. MIA: Just one quick question. 15 Just on your point about suggesting 16 that municipalities approve distribution rates and 17 service quality, I just wanted to get your view on 18 whether you saw -- where the municipalities are the 19 shareholders, if you see a conflict of interest where a 20 shareholder may also be approving its own rate? 21 I'm just thinking in terms of 22 fairness. 23 MR. COWAN: If a shareholder may also 24 be a...? 25 MR. MIA: If the municipality is a 26 shareholder of the LDC, and that municipality is 27 setting the rates. I'm just wondering if you see it as 28 a conflict of interest and maybe the Board is in a 759 OFA Panel 1 better position to set those rates. 2 MR. COWAN: No. I see no conflict of 3 interest whatever there. 4 We see local people cognizant of 5 local circumstances setting prices with the advice of 6 experts wherever they get them, the local engineers on 7 the PUC, the people they bring in. If they don't have 8 staff they can compare with the rates in the immediate 9 areas. They can compare with rates anywhere they wish. 10 They know what the upcoming costs will be. They have 11 some idea of what people can afford to pay and they can 12 do this relatively quickly without much in the way of 13 hearings. They can do it as an ordinary line of 14 business in the same way as I decide -- as a beef 15 farmer I don't decide what my price will be but I can 16 decide what I am going to sell them according to the 17 prices that are going. 18 So I don't necessarily have to be 19 wholly a price taker in that business, so I have some 20 discretion with respect to my prices. I can have 21 greater discretion. 22 But the conflict of interest I think 23 would -- I don't see how it arises. 24 MR. MIA: It would just be my concern 25 and just sort of canvassing your view on it is that as 26 a beef farmer there are other beef farmers and there is 27 competition, so you are forced by the market to set the 28 price, whereas an LDC is basically a monopoly -- 760 OFA Panel 1 MR. COWAN: Right. 2 MR. MIA: I'm just wondering if you 3 think there is any room for price setting. 4 MR. COWAN: It is a very local 5 monopoly and it is in the business as a municipality of 6 competing to attract more business, to attract more 7 residents. One of the things it can offer is a nice, 8 reliable, high-quality, reasonably priced -- we are not 9 saying necessarily the lowest price, we are saying good 10 service, reasonable prices. That is what people want 11 out of these things, I think. They will compete on 12 that basis. 13 Guelph and Kitchener competed that 14 way to get tire factories, machinery factories, 15 cigarette factories and beef processing plants for 16 years. The things they can offer these industries are 17 part of what they compete for. 18 We see that as having been good for 19 Ontario, that kind of local competition. We don't see 20 a cartel of -- well, we don't see the MEA, the 21 Municipal Electric Association as a cartel. 22 MR. MIA: Thank you. 23 MR. COWAN: There we are. 24 MS LEA: Thank you, Mr. Mia. 25 Dr. Cronin, do you have questions? 26 MR. CRONIN: Yes. 27 Hi, Mr. Cowan. 28 MR. COWAN: Good morning. 761 OFA Panel 1 MR. CRONIN: I understand that you 2 are, yourself, a farmer? 3 MR. COWAN: I am part of a family 4 farm. I am not the principal owner of the family farm. 5 That is a generation ahead of me. 6 MR. CRONIN: As you might be able to 7 tell from our earlier conversations, I have a great 8 deal of professional and personal respect for the 9 farming sector. 10 As an economist, I am aware of the 11 strides that have been made in the farming sector, not 12 just over the past 10 or 15 years, but really over much 13 longer time periods in terms of improving your 14 productive abilities. 15 Is my understanding generally 16 consistent with yours, that your efficiency has in fact 17 improved over the past 10, 20 years? 18 MR. COWAN: On average, efficiencies 19 have improved a great deal. People have survived 20 either on the basis of more debt, greater efficiency or 21 living on savings. In the long term, it has been 22 greater efficiency. 23 MR. CRONIN: And you have to consider 24 issues such as what are the prices of the items that 25 you are buying as inputs into the farm. 26 MR. COWAN: That's right. 27 MR. CRONIN: Capital. 28 MR. COWAN: Well, we tend to divide 762 OFA Panel 1 the assets into non-farm assets and farm assets. 2 Things we can buy from other farmers we can buy at very 3 good prices because they suffer the same price 4 discipline as beef farmers. You buy feed, it's gone 5 down too. You buy machinery and that machinery is 6 essentially made by companies that make mining 7 machinery and make manufacturing machinery and the 8 prices are in a different world. 9 MR. CRONIN: You are faced with 10 making those decisions all the time. You have to -- 11 MR. COWAN: Regularly. 12 MR. CRONIN: Yes. And I think you 13 mentioned in your prior discussions that you have less 14 subsidies going into the sector than were less true in 15 the past. 16 MR. COWAN: Since the completion of 17 the Uruguay Round of the WTO, World Trade Organization, 18 Canada has virtually eliminated all cash subsidies to 19 farmers of any kind. There is market protection left 20 for essentially dairy, poultry. Other than that, we 21 are pretty much open access. The dairy and poultry is 22 not subsidized, but border protected essentially, but 23 it's not subsidized. 24 MR. CRONIN: You pretty much have to 25 manage the risk. 26 MR. COWAN: The entire risk falls 27 back on the producer. 28 MR. CRONIN: I think, you know, if I 763 OFA Panel 1 could postulate a premise, and this is subject to the 2 discussion that occurred previously with Mr. Rodger. I 3 think he was trying to make the point that the proposal 4 was an attempt to instill some of the efficiencies that 5 I think are current in your sector now. 6 As well was the awareness of these 7 factors into the electric distribution industry, but 8 subject to, I think, a great deal of local control that 9 you are proposing in your statement, that is there 10 really isn't a guaranteed rate of return, and in fact 11 the local shareholders can set the rate of return at 12 zero. 13 In fact, we had discussions with the 14 Ministry about whether or not continuing operations of 15 the local utilities adds not-for-profit would in any 16 way run contrary to government's expectation. 17 MS LEA: Dr. Cronin, do you have a 18 question for the witness? 19 MR. CRONIN: With those 20 considerations in mind, would you be more comfortable 21 with the proposal with respect to the intention to have 22 the industry be more reflective of the kinds of risks 23 you are facing, that allowing local communities the 24 ultimate decision as to whether or not to run the 25 utility as a not-for-profit or for profit? 26 MR. COWAN: I would be more 27 comfortable -- I guess to some extent we have responded 28 to what we saw in the handbook. We had not been party 764 OFA Panel 1 to any of the discussion really prior to that. What we 2 saw in the handbook essentially was a proposal for a 3 PBR run primarily by the OEB and without a discussion 4 of what problems it was trying to solve. 5 We see the system of LDCs as not a 6 problem-free system, but a system which has run pretty 7 well historically and would take the point of view that 8 if Ontario were to hire 200 more regulators, then it's 9 probably some other problem of greater consequence that 10 they should address than trying to make LDCs more 11 efficient. I don't know which other problem, but there 12 we are. 13 It wasn't a priority for us to see 14 this centralized. We just didn't see a problem, so we 15 would opt for a rewriting of the handbook which 16 emphasized that the rates were to be set locally. They 17 didn't have to run for profit, that commercialization 18 was not a requirement. 19 Should an organization opt to run 20 itself commercially, then it might be subject to 21 different sets of requirements than if it opted to run 22 on a not-for-profit basis. That's the sort of thing 23 that we would be hoping for. In particular, with 24 respect to Ontario Hydro Services Company, which 25 currently there is no local control, we would like to 26 see rates set by country for Ontario Hydro Services 27 Company. 28 That county, if they set a rate that 765 OFA Panel 1 was too low or onerously high, they could live with the 2 consequences or correct it by bylaw. Yes, OHSC would 3 be having different distribution costs possibly in one 4 county than the next country right from the same 5 transformer potentially. We don't see that as a 6 problem. We see that as local control and see that as 7 a benefit. 8 MR. CRONIN: Maybe you will agree 9 with this statement. I am not supposed to make 10 statements, but I have a question on the end of it. 11 MR. COWAN: It's a way of thinking. 12 If it works, it works. 13 MR. CRONIN: The handbook and the 14 accompanying material was concise with respect to many 15 of these issues which had been elaborated in other 16 voluminous records put out by the Board and we might 17 have done a better job in elucidating some of the 18 issues that you are now raising. 19 However, I think while the issue of 20 commercialization, as I understand it, may be a moot 21 issue, the very issue that you are raising with respect 22 to local control of the pricing and many of the aspects 23 that you are discussing are in fact imbedded in the PBR 24 handbook. It's the intent of the proposal to allow a 25 fair amount of local control over those issues. 26 I think it is welcomed that you have 27 basically come to state from a real rural context your 28 concerns and hopefully maybe your concerns on some of 766 OFA Panel 1 these issues anyway would be somewhat mitigated. 2 MR. COWAN: We really look forward to 3 that, we really would. I guess the byword that many of 4 the members have been saying is the government has 5 promised lower electricity prices and the prices will 6 go down, but the bills will go up. They have been 7 seeing that concern on the distribution side. 8 From a point of view of farm survival 9 and business survival generally, cheaper electricity 10 with higher bills is not their idea of what it's about. 11 The distributions costs have to stay the same or go 12 down. Distribution costs by and large we think are 13 pretty reasonable, but we can think of no reason why 14 they should go up at any point in this process. 15 The transition cost, they have had 16 better transitions in the past than we are looking at 17 and we see no reason why there should be an additional 18 cost to finance this transition. 19 MR. CRONIN: Thanks a lot. 20 MR. COWAN: You are very welcome. 21 MS LEA: Thank you. Any other 22 questions for Mr. Cowan? There being none, Mr. Cowan, 23 thank you very much for your attendance here today and 24 for your presentation and for your attendance over the 25 past few days. We appreciate your input into the 26 technical conference. 27 MR. COWAN: Thank you very much for 28 the opportunity. 767 OFA Panel 1 MS LEA: Thank you. 2 MR. COWAN: You are very welcome for 3 it. 4 MS LEA: Are the presenters from 5 DTE/Probyn ready to begin? 6 Thank you. Please come forward. 7 --- Pause 8 MS LEA: Gentlemen, I don't know 9 whether you were here at the outset of the proceeding 10 this morning, but we are working under a bit of a 11 disadvantage today. One of our court reporters is not 12 here, so it is more than ever necessary to speak into 13 the microphone clearly, slowly, so that we can be sure 14 that we get every word on the transcript, which is what 15 goes to the Board. 16 I wonder if you could begin by 17 introducing each of yourselves and spelling your last 18 names and providing us with your presentation. 19 Thank you. 20 PRESENTATION 21 MR. ALLEN: Very good. 22 My name is Kim Allen, A-L-L-E-N and I 23 am the President of DTE/Probyn Energy Solutions. 24 On might right is Daria Babaie, 25 D-A-R-I-A B-A-B-A-I-E. Daria is the Vice-President 26 with DTE/Probyn Energy Solutions. 27 On Daria's right is Jim Musial, 28 M-U-S-I-A-L. Jim is with our team as a regulatory 768 DTE/PROBYN Panel 1 specialist. 2 MS LEA: Thank you. 3 Please go ahead. 4 MR. ALLEN: The first part of the 5 presentation Jim is going to walk you through, so I 6 will turn it over to Jim. 7 MR. MUSIAL: Good morning. 8 I haven't had a chance and I didn't 9 know the forum that we were going to participate in 10 this morning so I didn't prepare a written statement, a 11 summary statement. 12 MS LEA: That's fine. 13 MR. MUSIAL: So what we have done, on 14 August 12, was made a submittal to Mr. Pudge of the 15 OEB. Essentially then what I will do is walk through 16 that statement and summarize that statement and then, 17 as I understand, if there are questions to that 18 statement then we would hear those. 19 Is that the -- 20 MS LEA: Yes, that's fine, sir. 21 However you choose to present your views is agreeable 22 to us. 23 MR. MUSIAL: Okay. Well, what we 24 have done is on August 12 we made a submittal to the 25 OEB on behalf of Edison Sault. The statement -- 26 MS LEA: I'm sorry, Edison Sault? 27 MR. BABAIE: Sault Ste. Marie Public 28 Utilities. 769 DTE/PROBYN Panel 1 MS LEA: All right. That's great. 2 Thank you. 3 It's just that we have to make sure 4 that every proper name is either spelt or understood by 5 us so we know what it is. 6 Thank you. 7 MR. MUSIAL: The submittal was really 8 broken down into three parts, or four parts. We 9 discussed the rate adjustment mechanism and the PBR 10 filing. We made a comment to the establishment of the 11 initial rates. We talked a little bit about the 12 proposed service reliability indices and then also 13 followed up with comments on a proposed customer 14 service performance indicators. 15 If I could, then, I will move right 16 to the comments that we had on the rate adjustment 17 mechanism and the proposed PBR. 18 To begin with, one of our overarching 19 concerns was that the proposal submitted and presented 20 by the OEB, the draft rate handbook does not 21 memorialize, if you will, future policy with respect to 22 the distribution firms and their investment recovery 23 down the road in light of changes that could happen as 24 this policy rolls out. 25 Specifically with respect to 26 competitive services that may be deemed down the road 27 that an MEU may gear up to serve to enhance its 28 performance today. In doing so, in the future those 770 DTE/PROBYN Panel 1 services may be deemed to be competitive and then the 2 investment that the MEU may have made to become more 3 productive would be lost. 4 Second, our concern is that the PBR 5 mechanism only recognizes upside and limits upside 6 entrepreneurial rents to the MEUs and there are no 7 downside protections offered. 8 Given that there are a number of 9 mandates that are being imposed by the restructuring, 10 there are reporting requirements, there are rate 11 development requirements in terms of load research, 12 there are a number of filings that need to be entered 13 into by the MEUs as a result of this. There are a 14 number of services that the MEUs are going to have to 15 take on and they don't seem to be funded in the 16 proposal. 17 So while they have to take on these 18 new services, there aren't any ways to fund those it 19 seems, in the proposal. And their downside, they only 20 would tend to increase the downside potential of rate 21 of return implications for the MEU without any way to 22 fund those. 23 Third in terms of the PBR, the 24 adjustment mechanism, it's in a linear adjustment 25 mechanism. In the questions and answers that were 26 issued earlier this month as a result of the 27 discussions that the OEB had out in the province it 28 seemed that a number of MEUs had this same concern, 771 DTE/PROBYN Panel 1 that they were being penalized for past performance and 2 that if they had previously been -- embarked on 3 productivity enhancements that those past activities 4 would only tend to harm them in the future. 5 One of the questions and answers that 6 were presented seemed to indicate that if utilities had 7 previously exhibited that type behaviour that they 8 would continue in that type behaviour. While that is 9 probably true, one could also argue that there is a 10 point where there are diminishing returns and that the 11 PBR ROR proposal doesn't recognize that, they are -- 12 MS LEA: One moment, please, sir. We 13 just need to change -- 14 Again, unfortunately we just have one 15 person here, so -- 16 I'm sorry, please go ahead. 17 MR. MUSIAL: Another of our concerns 18 was with the Z-factor in that the Z-factor -- recovery 19 of Z-factor expenses were stated to be limited to those 20 expenses where prudent and prior maintenance would 21 have prevented the incurrence of those expenses. It 22 is just not clear what prudent and prior preventative 23 maintenance is. 24 The MEU is, in a sense, left to 25 manage its price index, or its costs, but if they do so 26 too aggressively in order to meet productivity factors 27 then they are, in a sense, faced to suffer a 28 disallowance of Z-factor expenses if they do incur 772 DTE/PROBYN Panel 1 those as a result of storm or catastrophic failure of 2 their system. 3 Another item of our concern was -- 4 and again, this was a concern that was brought up and 5 presented in the question and answer that was put out 6 by the Board -- is the concern that during the PBR 7 period there would be capital investment and there 8 would be regulatory lag associated with the recovery of 9 that investment. 10 One of the things that we proposed 11 was that to the extent that there was a system that is 12 growing, that either that historic growth or any known 13 future growth could be captured in the delta P, or the 14 price change, given a KVA-type growth factor. 15 Another item of our concern was 16 productivity factor development, and again, from the 17 question and answers presented, this seemed to be a 18 common theme among the people posing questions; and 19 that was that the productivity factor, as it is 20 presented, tends to penalize those utilities that 21 previously had embarked on productivity improvement 22 programs. 23 Another item of our concern was that 24 the uncertainty of restructuring costs seemed to be 25 being pushed on to the MEUs. We touched on this a 26 little bit earlier. 27 It seems that the MEUs are suffered 28 to perform the same traditional role that they always 773 DTE/PROBYN Panel 1 have; and that is in planning for growth on their 2 system and in planning for providing service on their 3 system. In some cases it is not clear that that 4 growth, or those investments in providing service, will 5 be recovered in the future. 6 Specifically, there is metering and 7 billing-type services that may need to be developed. 8 There is new technology that is being developed with 9 localized generation or even micro generation. To the 10 extent that utilities are making investment in 11 distribution equipment that may be at some point 12 stranded in the future, it doesn't seem that the Board 13 has essentially turned what has been known as the 14 regulatory compact into a regulatory contract for those 15 types of services. 16 Finally in terms of the PBR section, 17 there was a comment that we made regarding pricing 18 flexibility; not that the pricing flexibility that was 19 presented was not a step in the right direction, only 20 in terms that we feel that the MEU should be offered 21 more pricing flexibility to meet competition from 22 neighbouring MEUs. 23 In other words, if an MEU has prices 24 that are skewed or subsidized one class to another, in 25 order to be able to offer service and attract business 26 to its community -- similar to the gentleman before our 27 presentation, where he was talking, I think, that 28 Guelph and Kitchener were able to offer service based 774 DTE/PROBYN Panel 1 on local service. If one of those utilities now has 2 rates that are skewed to the benefit of a residential 3 class, for instance, versus another and it is not able 4 to address and bring its rates in line with its costs, 5 one of those MEUs would be at a disadvantage to the 6 other in attracting new business or residents to its 7 area. 8 The second part of our presentation 9 has to do with establishing initial rates. 10 Again, I notice that many of the 11 issues that we brought up were asked and answered in 12 that Q and A document put out by the OEB. 13 Initially our first view of this was 14 that the draft handbook starts out by asking us to 15 assume that existing rates are cost based and then go 16 forward and take a top-down approach to rate design. 17 Our comments are addressed to assume 18 that maybe they are not cost based and that is you take 19 a top-down approach design, or in other words starting 20 from the total revenue from the class and subtracting 21 out a derived cost of power, what is remaining is the 22 distribution charge. 23 In doing that, if subsidies exist 24 within the rates, they will continue to exist further, 25 further exacerbating the problem of one utility being 26 able to compete against another or one region being 27 able to compete against another with its prices. 28 So the rate handbook proposes that 775 DTE/PROBYN Panel 1 rates can be set in one of two ways. If a utility has 2 a cost of service and it wants to go through and 3 present that cost of service that it can establish 4 rates that way, or absent that cost of service that it 5 could go forward and use the top-down approach that has 6 been offered in the rate handbook. 7 One of the suggestions that we had 8 offered was that if the utility or the MEU did not have 9 that cost of service today, and likely does not, it 10 won't have that cost of service likely in place at the 11 start of the PBR period, but it may over time or within 12 the PBR period develop that cost analysis and want to 13 present the cost analysis subsequent to the start of 14 the PBR period. What we are asking is that they be 15 given the latitude to adjust their rates based on that 16 cost of service during the first PBR period or during 17 any other PBR period. 18 Another item in terms of rate design 19 that we have addressed was the definition of customer 20 class. We had suggested and requested that the OEB 21 consider a new definition of customer class other than 22 along the lines previously established, that being 23 essentially residential, large general service and 24 industrial rates, and rather create customer classes 25 based on the type of distribution service that those 26 customers are receiving. 27 Another item that we had requested 28 and suggested was that the proposed rate design 776 DTE/PROBYN Panel 1 currently is proposed to be a two-part rate design, a 2 fixed fee with a variable fee. For a couple of 3 reasons, we would request that the MEU be able to 4 choose between a fixed and variable fee and/or a fixed 5 fee for a couple of reasons. 6 One reason being that our view is 7 that the distribution service is essentially a fixed 8 cost service. It is fixed investment, it is fixed 9 labour and it makes the most sense that service be 10 priced on a fixed fee basis. 11 Another reason is that for utilities 12 that are facing a decline in the commodity throughput 13 those utilities ROR will be suffered to that decline if 14 they are forced into a two-part rate. 15 Our next issue in terms of rate 16 design had to do with determination of cost of power. 17 Again, this was an issue that was brought up in the 18 questions and answers. In a response the Board had 19 suggested that there may need to be some reconciliation 20 between what is proposed in the draft, and that is that 21 the utility use the specific coincident factors 22 established in the 1980s for each of the different 23 classes to determine the demands to be able to 24 ascertain the cost of power. If you use those directly 25 out of the tables they don't relate back to the actual 26 system demand at the time, and the Board's suggestion 27 was that there may need to be a revenue reconciliation. 28 I am not sure if it will work out if you do a revenue 777 DTE/PROBYN Panel 1 reconciliation or a demand reconciliation but I think 2 it is the same thing. So in a sense that issue has 3 already been addressed in your Q&A. 4 Another thing that we discussed was 5 the coincidental load factor data that was available. 6 It has been stated that data came from the 1980s. If 7 utilities, if the MEUs, are going to continue to use 8 the information provided by the Board to do their rate 9 design as opposed to embarking on their own load 10 research programs and developing their own cost of 11 service analysis, if they are going to continue to rely 12 on that data we would suggest and request that data be 13 updated to reflect the changes in energy consumption 14 over the last decade, specifically the introduction of 15 natural gas as a competing alternative to electric. 16 We have a similar comment in terms of 17 incremental distribution costs. Again, that data was 18 stated to be derived from the 1980s. It would be our 19 impression that data would probably have increased 20 since that time. Again, if utilities are going to use 21 the Board's data rather than create their own they 22 should have the most current data at their disposal. 23 Another item that we discussed in our 24 rate design proposal related to the request for 25 information from consumers. We would request that at 26 some point that the utility would be required to give 27 customer information to potential suppliers but that 28 data should be limited to the data that is on hand, and 778 DTE/PROBYN Panel 1 that if the utility itself had to perform analysis to 2 be able to provide the data to the supplier that in 3 itself is not a kind of a public good service, if you 4 will. That is a competitive service that anybody could 5 do given the data, and that if the utility were 6 suffered to do that then they should be compensated for 7 doing that. 8 Our third area of response related to 9 service reliability indices. 10 MR. BABAIE: Other parts of our 11 submission was related to service reliability and 12 service quality indices and the performance. 13 The PBR Rates Handbook has considered 14 a number of indices, measures related to reliability, 15 including CAIDI, SAIFI and SAIDI. There are two 16 paragraphs that I am just using from the PBR Rates 17 Handbook, and its service quality measures saying that 18 distributors whose performance falls below the minimum 19 service quality standards for indicators for which 20 monitoring and reporting is required must include a 21 remedial action plan with their annual reports. It 22 continues stating that it is anticipated that in a 23 second generation PBR plan there will be sufficient 24 data collected to set industry service quality 25 performance standards and once these standards have 26 been established PBR incentive mechanisms will be 27 introduced on the service quality indicators with 28 economic consequences, and economic consequences is the 779 DTE/PROBYN Panel 1 one I am emphasizing now. 2 These two paragraphs I read, they 3 raised a number of important issues here and challenges 4 for the end-use to face in the future. 5 First of all, utilities across the 6 province invested on reliability programs not in the 7 same way in the past. There have been different 8 programs, there is different funding towards improving 9 their reliability of the system. Some utilities 10 adopted modern technology including SCADA(ph), 11 aomadthum(ph) system and integrated with the customer 12 services and so on and many years of capital 13 investments in their distribution systems, and as I 14 said, customer services operations and develop 15 preventive maintenance programs that help them improve 16 their system reliability and manage better customer 17 interaction. At the same time some others haven't done 18 that, and even they don't have any of those measures 19 and they haven't collected those system reliability 20 measures. 21 In light of this argument, the PBR 22 Rate Handbook states that utilities that have achieved 23 three-year data on this index should, at minimum, 24 remain within the range of their historic performance. 25 We believe this does not create a level playing field 26 for utilities and does not treat them equally in the 27 start of the new regulation concerning the improvement 28 of system reliability and their performance. 780 DTE/PROBYN Panel 1 The PBR Rate Handbook assumes that 2 the causes for a drop in performance below minimum 3 service quality standards are all controlled with 4 nature, meaning that the utility could control the 5 causes for those. 6 To basically support this argument 7 I'm using this statement: 8 "...distribution performance 9 falls below the minimum service 10 quality of standard for 11 indicators for which the 12 monitoring and reporting 13 required must include a remedial 14 action plan with their annual 15 reports." (As read) 16 So they are assuming that there 17 should be an action plan on behalf of the MEUs to 18 address a number of those causes that basically 19 contribute to the system reliability. 20 Basically, our request here is that 21 to solve those performance measures that basically have 22 some contributions, it changes from one year to another 23 due to some reasons, some causes, including adverse 24 weather and some type of storms, and they are not of 25 any controllable nature to the MEUs. 26 Also, the information related to 27 historic performance prior to 2000 should remain 28 statistical and should not set a stage in the first 781 DTE/PROBYN Panel 1 generation of PBR for any possible penalizing of 2 utilities that would operate in the second generation 3 of the PBR. 4 Again, we talked about associating 5 the financial type of consequences associated with not 6 meeting those standards. 7 At the start, we believed that those 8 utilities that took proactive actions in the past and 9 invested in their system and improved the reliability 10 of system operations should not be positioned in a 11 disadvantage as compared to those who were not 12 proactive concerning reliability improvement in the 13 past. A level playing field, again, should be 14 established in that respect. 15 In terms of definitions of those 16 measures, the standard is not clear. Common 17 definitions, basically, are needed. There are 18 different definitions. 19 Number one, some utilities define 20 "customer" at the meter point versus others defined 21 customers differently. So that basically results in 22 different numbers. Are we defining really what those 23 basic measures are? 24 So the definitions are very 25 important. 26 At the same time, there are a number 27 of other things, like reliability measures also should 28 only consider, in our view, the total minutes of 782 DTE/PROBYN Panel 1 unplanned sustained customer interruption to 2 characterize the average length of time or frequency 3 associated with those interruptions. 4 In that respect, we have elaborated 5 in our submissions that basically there are a number 6 reasons that are not in the control of the MEU. 7 First of all, number one, we are 8 unbundling, the Act is unbundling, all the generation 9 transmission distribution. If that is the case, if you 10 look at Table 2.5 in the handbook for the reliability, 11 there are a number of factors that we believe must not 12 be included there. 13 One is the scheduled or planned 14 outages. We believe that the utilities need to go 15 through the planned outages. 16 That is basically another indication 17 not of performing well but an indication of enhancing 18 the system. So measuring that time frequency as a 19 result of planned outages, that is part of the standard 20 measure. Putting that as part of the bar for the MEUs 21 to perform, we don't believe that is a proper way of 22 treating MEUs. 23 Another one which basically we listed 24 there too, those outages that are explained in the 25 system, as again Table 5.2 indicates, are several 26 causes including tree contact, defective equipment, 27 loss of supply, weather accidents, et cetera. We think 28 these should not be included. A number of these causes 783 DTE/PROBYN Panel 1 happen outside the distribution utility service 2 territory and facilities and we believe must not be 3 considered in the calculations. 4 In terms of loss of supply, Table 5.2 5 states that: 6 "Customer interruptions view 7 problems in the bulk electricity 8 supply system." (As read) 9 Again, when unbundling generation 10 transmission distribution we don't think distribution 11 utilities should be responsible for those interruptions 12 that are happening on the supply side. 13 An example of that, you could have 14 some number of interruptions that in the generation is 15 done or with transmission there could be some problems 16 due to the equipment failure and that results in a 17 number of interruptions on the MEUs distribution 18 system. 19 In the transmission substations there 20 are a lot of failures or faults that occur as a result 21 of one box subject to default and that results in a 22 number of voltage sags in the distribution system. So 23 having that interruption in the transmission substation 24 is not in the control of the distribution MEU and it is 25 not reasonable to include it as part of the 26 calculations. 27 However, that could be useful 28 information for an MEU in terms of saying: How 784 DTE/PROBYN Panel 1 reliable -- you know, they are getting their supply 2 from the different suppliers and use that one as 3 basically a measure of the performance of the supply 4 and use that as part of the contract negotiations later 5 on, you know, and basically request a number of 6 remedial actions for those action plans that you are 7 suggesting from the supplier. But the MEU itself must 8 not be responsible for that type of performance. 9 We also believe that additional 10 exclusions should be considered and they are not listed 11 and those are including major events. The major events 12 should include those outages that are caused by 13 earthquakes, fire, storms of sufficient intensity to 14 give rise to a state of emergency being declared by 15 either municipal or the province or the federal 16 government, the different levels of governments. 17 Under any of these type of major 18 events, the duration of frequency outages must be, we 19 believe, excluded from any PBR calculations. 20 In addition, we believe that that 21 section on the performance reliability basically comes 22 short in terms of addressing the number of issues 23 related to labour disputes and strikes that could be 24 there and could impact a utility's performance. Those 25 who have been working in the MEUs, the electric MEUs, 26 and have been involved with those labour disputes and 27 labour unrest would appreciate where we are coming 28 from. 785 DTE/PROBYN Panel 1 Table 2.5 also identifies flying 2 interference as another cause for service interruptions 3 and holds the MEUs responsible for those type of 4 calculations and defines it as customer interruptions 5 beyond the control of the utility such as animals, 6 vehicles, digging, vandalism, sabotage and flying 7 objects. 8 We believe causes such as animals 9 entering a substation could be considered or should be 10 considered for analyzing the performance reliability as 11 the utility could take a number of measures to protect 12 against animal interference. 13 Power outages as the result of error 14 or a mistake made by a customer in the case of digging, 15 a vehicle hitting the utility pole and sabotage, those 16 type of things should not be considered at all. 17 The performance measures also, we 18 believe, should reflect how well a utility is proactive 19 with respect to system reliability and how much it is 20 living up to the commitment they have towards their 21 customers rather than make it responsible for those 22 factors that, again, are not of any control. 23 SAIDI, CAIDI were developed, if you 24 look at the history of those by utilities, to basically 25 try to find out the causes and take the necessary 26 actions and to improve their system reliability and 27 improve the performance to their customers. 28 This practice has been there even 786 DTE/PROBYN Panel 1 before the Competition Act was introduced. At that 2 point basically, historically, if you look at the 3 number of things they included as possible generation 4 targets in their calculation, it was because they were 5 very proactive in terms of dealing with their supplier 6 and, you know, those people obtaining the power. 7 That relationship has been there 8 always, you know. They are working very close with 9 each other to address a number of those issues. Now, 10 this type of unbundling, you expect that those 11 performances be separate and unbundled as well. 12 We believe that the former outages, 13 and summarize these types of outages and causes, should 14 not be included in the calculations of PBR reliability 15 measures. 16 Number one, planned outages, any 17 outage of any due except in relation to where the 18 customer is notified prior to any loss of supply. 19 Outages occurring within the 20 timeframe of a major event or an outage event that is 21 caused by earthquake, fire, storms and those of 22 sufficient intensity that basically result in those 23 states of emergency. 24 Outages involving secondary 25 distribution line transformer only or service only 26 outages and meter related outages. 27 Customer caused outages because of 28 negligence, mistake or errors made at the customer's 787 DTE/PROBYN Panel 1 home, office, plant, this should not be included. 2 Outages due to vehicle accidents, 3 vehicles hitting the poles is an example of that, and 4 those incidents beyond the control of the utility, 5 including sabotage in one of those centres, they should 6 not be included. 7 Lastly, outages due to generation, 8 transmission lines and transmission substation failures 9 and those that could basically also be a part of IMO 10 related facilities, you know, shortcomings. 11 We basically in our submission put 12 forward a proposed code and the causes that we would 13 want more to consider those from. The ones which are 14 not under control, we are suggesting that they should 15 be considered as a means of tracking the performance of 16 the supply or transmission utilities and try to 17 basically pinpoint those causes and basically use it as 18 a type of enhancement of the system in the future by 19 taking a number of maybe joint initiatives. 20 Now I would like to ask Kim Allen to 21 walk you through the next section. 22 MR. ALLEN: The next section that we 23 talk -- 24 MS LEA: Just before you begin, Mr. 25 Allen, I will have to call a break soon. I was 26 wondering, do you have any estimation of how much 27 longer your presentation itself will last? 28 MR. ALLEN: Maybe 15 minutes max. 788 DTE/PROBYN Panel 1 MS LEA: Okay. Then I will call a 2 break at this time. We will reconvene at ten to 3 eleven, please. 4 Thank you. 5 MR. ALLEN: Thank you. 6 --- Upon recessing at 1034 7 --- Upon resuming at 1053 8 MS LEA: Could we reconvene, please. 9 Please go ahead. Thank you. 10 MR. ALLEN: Good. Thank you. 11 I'm going to go through our 12 submission on the customer service performance indices. 13 To walk through on the specific ones, 14 the first service performance that is recommended by 15 the Board is related to the connection of new services, 16 and they talk about: Services must be connected within 17 five working days from which all service conditions are 18 satisfied, including the requirement from electrical 19 inspection. 20 I guess we raise the issues of a 21 number of ambiguities about who actually will set those 22 service conditions to ensure that they are actually 23 satisfied and some definition around those. 24 Would it be the utility that would 25 just do it from their own internal policies to say: 26 Here are the services that you must satisfy. In the 27 case of Sault Ste. Marie, being very comfortable, 28 saying: If we are in control of setting those 789 DTE/PROBYN Panel 1 standards, meeting the five day requirement will be 2 extremely easy; however, if it is the regulator that 3 sets them it would be -- may be much more onerous. 4 Does the condition of service 5 accommodate seasonality, the summer versus winter 6 trenching, a major concern for our client on what 7 happens with winter servicing. 8 What happens if within the five 9 working days a major storm arrives and it is impossible 10 to meet those service standards? What types of 11 penalties will be imposed on the utility for not 12 meeting those when abnormal conditions arise and is 13 there some type of notion that under major storm 14 conditions that timing period may be put on hold? 15 Will the condition of service include 16 the civil work that must be completed by the customer 17 before any connection is made? Can the utility specify 18 that? 19 Will the service standard policy -- 20 again just reflect on the winter excavation that may be 21 required. 22 How many days, weeks of lead time 23 will be allowed in it. For example, on ordering some 24 transformers for various different customers the 25 equipment may require 16-24 week lead time. Is it 26 after the transformer arrives that the clock starts 27 ticking for connecting some of these services? 28 Then I think back to our same point 790 DTE/PROBYN Panel 1 with service standards with any of the major events, 2 earthquake, fire, storms, something that may give rise 3 to condition of a state of emergency. We believe those 4 things should be excluded. 5 The second item around the service 6 standard with underground locates, one of the big 7 concerns we have with it is that frequently markings 8 are removed by the public or by contractors or as other 9 construction activities are going on and the utility 10 may go out and locate the same cable a second and third 11 time. 12 Now, do each of these count as a 13 response into their statistical purposes or does the -- 14 you are only really serving one purpose of the locate, 15 is it the five days to handle those three that comes 16 into place? 17 Furthermore, the extreme weather 18 conditions would cause a delay and I think some type of 19 consideration for the utility adjusting service 20 standards for those extreme conditions would be very 21 helpful. 22 The third area that talked about 23 telephone accessibility, it is a slightly different 24 concern. Because one of the concerns that we have in 25 here is that we believe through use of modern telephone 26 technology -- and we are suggesting be included in 27 section 5.2.3 where it talked about: The provision of 28 voice mailbox and answering machine does not constitute 791 DTE/PROBYN Panel 1 this standard, we find it very restricting because 2 modern telephone technology may actually enhance the 3 utility's ability to provide these types of service. 4 For example, there is a company 5 providing a service to 60 million of the United States' 6 electric customers that handles everything through 7 automated technology so, in effect, when a storm or 8 something hits the customers cannot get a busy signal. 9 However, that would not -- it is, I guess, a vastly 10 enhanced service over anything that any Canadian 11 utility is offering right now, however it wouldn't meet 12 the Board's requirements. 13 So I think it seems kind of 14 restrictive that you have a technology restriction when 15 you can actually offer a better service through the use 16 of technology. This would allow people to call in, 17 lodge the call and allow the utility to use that type 18 of statistical information to better handle and manage 19 that whole storm restoration process by getting 30,000 20 calls within the first hour where they couldn't 21 physically do that with the number of staff that they 22 may have in place. 23 I guess with some of the ambiguities 24 we would like to see some clarity on the definition of 25 what does it really mean to be answered within 30 26 seconds. Is that just someone saying hello or is it 27 actually dealing with somebody who can actually do 28 something for you? 792 DTE/PROBYN Panel 1 Is a busy signal or a call put in a 2 queue regarded as answered, so you get the initial 3 hello from the switchboard operator and then you are 4 put in a queue waiting for -- those types of ones that 5 the customer is not getting served. 6 Does a call abandoned before they got 7 through count in the statistics as not being answered? 8 What consideration for the calls that 9 are made after the office is closed? 10 What happens when the utility is 11 experiencing an outage or the general inquiry number 12 becomes busy simply because there is an overload of 13 customers calling in? How do all those factor into the 14 standard to answer the call within 30 seconds 65 per 15 cent of the time? 16 The fourth area regarding with 17 appointments where appointments must be kept 90 per 18 cent of the time and if the appointment cannot be met 19 the customer must be notified? 20 The standard is not clear enough or 21 is ambiguous around how is it that it is defined that 22 it is necessary or unnecessary to meet the customer? 23 For example, many services could be performed in the 24 office versus on the customer premise. So is that a 25 necessary appointment with the customer or an 26 unnecessary one? 27 What happens if the customer's 28 request for a data is not reasonable and the utility 793 DTE/PROBYN Panel 1 representative cannot satisfy the customer request, 2 such as a meeting, for example, "I want to meet you in 3 an hour from now"? 4 What happens if the customer requests 5 a meeting for off working hours? Would the utility be 6 allowed to charge a premium to meet the customer in 7 something with off working hours to help satisfy that 8 request? 9 What happens if the customer requests 10 morning/afternoon and is in conflict with the 11 availability? 12 How to deal with the situation that 13 the customer urges to have a specific date at the cost 14 of the staff being pulled off of their normal duties? 15 Can the utility impose some additional ones that if 16 it -- because it is absolutely essential they meet at 17 this time, can the utility impose some additional cost 18 to compensate from being pulled off some other duties? 19 What happens if an emergency occurs 20 and there is no time to notify a customer? 21 Very often utilities, again such as 22 Sault Ste. Marie, will have -- might have two people 23 out doing this type of field work with customers and 24 when an emergency hits they are pulled to restore 25 power. 26 What happens if an appointment can't 27 be kept and the utility is unable to notify the 28 customer since they cannot be reached; the utility 794 DTE/PROBYN Panel 1 attempts to call the customer and there is no one home? 2 Does that allow the utility not to be counted as a not 3 met appointment? 4 In the fifth area, it is written 5 responses to inquiries and it talks that: Written 6 information by a customer or an agent of a customer 7 relating to a customer account will be within 10 days 8 following the receipt of the request, and the written, 9 the standard is 80 per cent of the time. 10 The standard is not clear or offers a 11 number of ambiguities around the definition of 12 responding to requests. 13 I think that relates to some of the 14 comments that Mr. Musial was talking about a little 15 earlier, that if the request is simply a statistical 16 one of providing readily available information, that 17 may be readily provided. If it is something that 18 requires some analysis there may be a cost with it and 19 there may also be additional time required to pull 20 those together. So I think some definitions about 21 those types of ones. 22 Does responding to a request mean 23 that the problem is solved or simply acknowledging that 24 the customer has requested you to do something? Would 25 that satisfy the standard? 26 What happens if the customer's 27 account is not updated and the information is not 28 available within that 10 days following the request? 795 DTE/PROBYN Panel 1 This would frequently happen with things where -- or 2 could frequently happen where issues of property 3 transactions, they may fall within the meter reading 4 cycle, and someone is asking for an estimate of what 5 that would be before the house closing happens or the 6 business closing, any of those sale transactions -- 7 consideration for all those may work. Any abnormal 8 business circumstances recognized by the standards such 9 as labour disputes, strike storms, that may prevent the 10 utility from meeting its guideline, and should there be 11 any of those included as exceptions into meeting the 12 standard, and does the utility require an expensive 13 record-tracking system to be able to satisfy the 14 standard. Many utilities don't track us right now and 15 so it would be an additional cost to satisfy the 16 standard. 17 Emergency response. The minimum 18 emergency trouble call, i.e. fire, ambulance, police, 19 et cetera, will be responded to within 120 minutes in 20 rural areas and 60 minutes in urban areas, the arrival 21 of a qualified service person on site will constitute 22 the response. The minimum standard must be met at 23 least 80 per cent of the time. 24 The concerns we have around that, 25 around that standard, does the standard assume that the 26 large, medium and small-sized utilities have the same 27 level of resourcing for trouble crews into those areas? 28 Are utility staff in a position to act as first 796 DTE/PROBYN Panel 1 respondents such as fire, police and ambulances to be 2 out there? Does the standard recognize the situation in 3 which the utility has prioritized work related to 4 multiple emergency responses? 5 For example, in storms there are a 6 number of calls and if we take one of those we might 7 get -- the utility could get thousands of calls within 8 the first hour on a multiple storm situation. It is 9 physically impossible to have staff respond to each one 10 of those individual calls and so do you satisfy one of 11 those calls but you are actually working on all of them 12 simultaneously? 13 What happens if multiple lines are 14 down and there is only one trouble crew available? 15 Utilities historically have prioritized and tried to 16 get the most critical lines back first and work their 17 way through that. Does the standard assume the 18 response time during severe storms as the same as under 19 normal utility operations? Again, touching on that. 20 How does the standard treat any of the abnormal major 21 events and how would that be adjusted? 22 One of the other kind of overriding 23 concerns that we had with that, that staff, we wouldn't 24 want this standard to have drive staff into doing some 25 unsafe acts. For example, driving at speeds that would 26 require them to break legal speed limits simply to get 27 out to satisfy a concern. 28 So the overriding concern of many of 797 DTE/PROBYN Panel 1 the things related to a time-limited service standard 2 were really around the whole staff and the associated 3 public safety around dealing with those. We were 4 suggesting in this section that it really be revised to 5 say that the utility must file an emergency trouble 6 call response plan with the OEB and the plan would 7 include response times for the arrival of qualified 8 service personnel in rural and urban areas and that 9 those standards must be met at least 80 per cent of the 10 time. 11 So we think that the uniqueness of 12 utilities, particularly with our client who was having 13 a concentration of urban and a number of rural 14 customers, that some of the standards in the urban 15 areas would be relatively easy to meet, in the rural 16 areas it would be very difficult to meet. I think the 17 recognition for that variance would certainly 18 accommodate the utility in those areas. 19 I would like to just, just before we 20 sum up, I would like to turn it back to Jim Musial for 21 a second to talk a bit about how, I guess, the answer 22 to a number of the questions really kind of ties some 23 of the material together. 24 MR. MUSIAL: Going back to the PBR 25 and the productivity factor in the PBR -- 26 MS LEA: Could you just put the 27 microphone slightly closer to you, sir? Thank you. 28 MR. MUSIAL: I am going back to the 798 DTE/PROBYN Panel 1 productivity factor and the relationship between IPI 2 and productivity factor on rates of return that the 3 MEUs might be able to obtain. 4 There was a number of questions and 5 answers. When I refer to questions and answers it is 6 that which was published by the Board, and those were 7 questions and answers from the seminars that you held 8 over July 13th to July 23rd. But it seemed that there 9 was a broad concern about utilities that had previously 10 embarked on productivity factors or that viewed 11 themselves as being highly productive and that the PBR 12 mechanism as proposed might put them at a disadvantage 13 to those utilities that hadn't embarked on those. 14 One of the responses to the questions 15 states that while that is true there is a number of PBR 16 factors that an MEU could select from and then it 17 states that: 18 "Furthermore that every utility 19 will be able to adjust its rate 20 ceiling based on the change in 21 the IPI even if its own input 22 prices say was less than the 23 IPI." (As read) 24 I would just like to -- my view of 25 that relationship, just discuss that a little bit. 26 Given that there are a number of new 27 requirements that are being imposed on some of the MEUs 28 and some of the MEUs may have staff already in place 799 DTE/PROBYN Panel 1 that might be able to address these requirements, some 2 of them that are smaller might have to take on staff or 3 consultants and pay them to respond to those 4 requirements. 5 You know, we are talking about a 6 number of court reporting requirements. There are rate 7 filings, uniform system of accounts now is being put in 8 place where they may have to create accounting systems 9 and bring on accountants. There is a reporting 10 requirement about service quality. There is the PBR 11 filings. You have now to keep track of customer 12 responses which in the new term would probably likely 13 increase due to requests for information to be able to 14 give to the suppliers. There is load research 15 requirements that the MEUs are going to have to take 16 on, cost of service requirements. You could have new 17 billings systems, new metering systems that they will 18 have to take on to be able to provide the service in an 19 unbundled fashion. They will have perhaps case or 20 litigation expense that they maybe never faced before. 21 They may never have had an intervenor in a case before. 22 So they will need to be able to respond. 23 So we have a number of things that 24 would tend to increase their input price, is I guess my 25 point. None of those things, and I hate to say that in 26 that we are being paid by an MEU, but none of those 27 things probably would tend to increase their 28 productivity. So in effect it is just a drain on their 800 DTE/PROBYN Panel 1 ROR with no upside. 2 Thank you. 3 MR. ALLEN: Thank you. 4 I would just like to pull together a 5 summary and then open it up for questions. 6 Today, our comments on behalf of 7 Sault Ste. Marie are really intended to hopefully 8 provide that PBR provides strong incentives for 9 utilities to continue to improve their efficiencies, 10 resulting in lower rates for customers and potentially 11 high profits for the shareholders. 12 The second is that fair and equitable 13 unbundling of rates into distribution and commodity 14 components and further simplify the procedure to 15 unbundle the existing rates and improve their accuracy. 16 The third item was that a 17 market-based rate of return as well as the cost 18 incurred by the utility for the transition to the new 19 marketplace being implemented in Ontario. 20 Fourth, that a level playing field is 21 created amongst all distribution utilities. 22 Fifth, that true incentive-based 23 regulation where utilities with good performance have 24 the ability to be rewarded by further improving their 25 performance, and finally that the OEB does not 26 disincentize the stretch entrepreneurial behaviour that 27 our client is trying to seek. 28 The four kind of key areas were items 801 DTE/PROBYN Panel 1 related to the Z-factor and the growth components. We 2 think those are very significant in creating that level 3 playing field. 4 Regarding rates, we think that the 5 key is that the utilities should, at any time, be able 6 to submit its own unique plan based on a 7 cost-of-service study. Noted in the distribution 8 handbook back in -- some of the work that was done by 9 the task force back in May, it didn't preclude that 10 definition or redefinition of customer classes which we 11 think go hand and glove with a resubmission of the 12 cost. Depending on how the utility wants to look at 13 its customers would relate to those costs. 14 In the third area we talked about 15 reliability standards. When you look back to the 16 creation that was involved back in the early days, the 17 creation of those types of standards with the Canadian 18 Electrical Association, they were really designed for a 19 vertically integrated utility to look at full 20 statistical performance and how applicable those are 21 for monitoring and measuring performance of 22 distribution utilities I think may fall a bit short. 23 So that is why I think all the listing and the 24 definition of all the things that needed to be 25 excluded. 26 Then, in the final area, we think 27 that with all the customer service managers there 28 should be clarity of definition but overriding that 802 DTE/PROBYN Panel 1 each of them should be driving to enhance that 2 entrepreneurial behaviour as opposed to putting up 3 barriers that the utility may just respond to meet a 4 standard as opposed to doing what is best for its 5 customers. 6 With that we would like to thank the 7 Board for the opportunity and open up to questions. 8 MS LEA: Thank you very much, 9 gentlemen, for your presentation. 10 Questions, then, for these 11 presenters? 12 Mr. Rodger? 13 MR. RODGER: Thank you, Ms Lea. 14 Just one area perhaps for Mr. Allen. 15 I note in your prefiled submission -- 16 for the record it is page 9 -- that you explore the 17 issue of streetlighting rates in the context of the 18 proposed PBR Handbook. I gather from your submission 19 that at present, at least, in Sault Ste. Marie you 20 consider streetlighting as part of the general service 21 class. Is that correct? 22 MR. ALLEN: That's correct. 23 MR. RODGER: Is the streetlighting 24 system currently owned by the municipality or is that 25 part of the utility? 26 MR. ALLEN: No. It's currently owned 27 by the municipality. 28 MR. RODGER: I see. 803 DTE/PROBYN Panel 1 I gather from your submission that it 2 is your view that the Board's proposal to separate the 3 distribution cost component from the commodity 4 component of streetlighting, if you were to use the 5 Board's figures, that would have the impact of 6 increasing the rates on the distribution side of 7 streetlighting in the Sault. Is that correct? 8 MR. ALLEN: That's correct. 9 MR. RODGER: Do I take from that 10 that, at least historically, you have been able to make 11 that separation in terms of what the commodity charge 12 is and what the distribution charge is for 13 streetlighting in the Sault? 14 MR. ALLEN: Yes. It is very clear 15 the delineation between who owns which of the 16 components and it is really a design of the 17 streetlighting system. 18 The Sault operates with a couple of 19 different designs but is relatively easy to track from 20 the point of supply to the streetlight, and beyond is 21 owned by the municipality. Anything up to the point of 22 electrical supply is owned by the utility, so those 23 separation of costs are very easy. 24 MR. RODGER: I wonder if I could ask 25 you to comment, then. 26 If under the Energy Competition Act 27 distribution is defined as conveying electricity at 28 50 kV or less and consistent with the Board's approach 804 DTE/PROBYN Panel 1 for streetlighting of separating the commodity from the 2 transportation of the distribution aspect, could you 3 comment on a suggestion that perhaps the distribution 4 assets pertaining to streetlighting might more properly 5 reside in this new market with the distribution utility 6 and form part of the regulated distribution network? 7 MR. ALLEN: I think that is a very 8 positive suggestion. 9 Maybe the utilities historically 10 have -- and the streetlighting has gone back and forth 11 between who actually owned it, whether it was the 12 utility or the municipality. Both tried to have the 13 other party deal with the associated difficulties with 14 it. 15 But if the Board developed a 16 consistent service standard for what was required for 17 streetlighting, such as illumination levels on these 18 types of streets, and treated this as another product 19 that the distribution utility would have, I know Sault 20 Ste. Marie would be certainly very in favour of doing 21 those types of things with it. 22 The whole notion that the majority of 23 streetlighting cost is actually in the commodity, the 24 sale of the electricity, and so now with the 25 municipality being the shareholder I think the 26 realignment of those costs to remove it from the tax 27 roll makes a whole lot of sense. 28 MR. RODGER: Thank you, sir. Those 805 DTE/PROBYN Panel 1 are my questions. 2 MS LEA: Thank you, Mr. Rodger. 3 Mr. Grieve? No questions. 4 Mr. White? 5 MR. WHITE: Can I stick with the 6 streetlighting item? I found your comments 7 interesting. 8 Where you had an overhead 9 distribution system within a municipal electric 10 utility, I take it that streetlighting isn't separately 11 metered within the utility? 12 MR. ALLEN: Correct. 13 MR. WHITE: In terms of the energy 14 consumption, what component of that energy consumption 15 would be off peak versus peak? 16 Let's not worry about the 17 percentages. I'm sorry. Let me try and be helpful. 18 If we are looking at an energy 19 utilization on a distribution system that is largely 20 off peak, then is it fair to draw from that, based on 21 your technical background that the incremental 22 distribution costs for streetlighting would be lower 23 than it would be for other classes of customers within 24 the utility -- typically expected? 25 MR. ALLEN: Yes. The relative costs, 26 if you look at it and think of it in terms of a 27 customer's -- the cost that is related per customer in 28 some preliminary calculations with Sault Ste. Marie is 806 DTE/PROBYN Panel 1 somewhere between $1.50 per month and $2.00 per month 2 per customer would be the all-in cost of streetlighting 3 and the component in there is -- roughly about 75 per 4 cent is power cost. 5 MR. WHITE: Let's talk for a minute 6 just a little more about the streetlighting. 7 Would there be as much as 5 per cent 8 of the streetlighting in Sault Ste. Marie that might 9 have dedicated transformation associated with the 10 streetlighting, in other words, a step down from 11 primary distribution voltage to streetlighting voltage, 12 or would it be less than 5 per cent? 13 MR. ALLEN: It would be slightly 14 actually more than 5 per cent, simply because of the 15 rural mix. 16 If you look at urban Sault Ste. Marie 17 it would certainly be less than 5 per cent. In some of 18 the rural areas there is a dedicated streetlight, if 19 you like, at an intersection. 20 MR. WHITE: With the associated 21 transformation. 22 MR. ALLEN: With the associated 23 transformation in there. 24 But typically in the urban setting 25 and wherever possible there isn't dedicated 26 transformation for streetlighting. 27 MR. WHITE: Okay. 28 Can I now go back to the comment that 807 DTE/PROBYN Panel 1 talked about municipal utilities spending additional 2 capital on billing systems and other similar related 3 systems? 4 Let me try and characterize what I 5 think I heard. There's some concern on the part of the 6 utility that it may make a capital investment or other 7 similar type resource investment, whether it be staff 8 development or purchase contract services even that 9 might become a stranded asset, if I can use the term 10 stranded or stranded investment, without the benefit of 11 a CTC if the service were considered contestable down 12 the road. 13 MR. MUSIAL: Yes, that's correct. 14 Even more so than that, even the lines themselves, 15 given technology turnover the lines themselves could 16 become stranded at some point in the future so you 17 might want to consider, rather than a 35 or 40 year 18 recovery period on that investment, a shorter recovery 19 period because of technological obsolescence. 20 MR. WHITE: Have you thought about in 21 terms of those assets that might become stranded 22 because of a contestability decision, have you thought 23 about how a compensation process might work for the 24 municipal utility that would be equitable? 25 MR. MUSIAL: I guess the question is 26 equitable to who? Equitable -- 27 MR. WHITE: That's the beauty of the 28 word "equitable". 808 DTE/PROBYN Panel 1 MR. MUSIAL: Yes. 2 MR. WHITE: It says it's spread 3 around. 4 MR. MUSIAL: Yes. I guess, you know, 5 equitable to the utility would be at least the recovery 6 of its undepreciated asset through some type of CTC 7 What would be equitable to the 8 province or to the consumers themselves, you know, 9 might be some recognition of the utility knowing going 10 in that if it embarks on that program that it might be 11 a contestable service down the road and it should have 12 known better. 13 MR. WHITE: I think I hear you 14 identifying the need for the Board to bring the 15 decisions regarding contestable, the decisions to 16 change the contestability of services to a hearing such 17 as we are in now to give these people a chance to -- 18 MR. MUSIAL: I think so, or to just 19 recognize that if those services that the utility 20 embarks on were to become contestable that it would 21 have some assurance of the recovery of its, you know, 22 stranded cost that they will in the future. 23 MR. WHITE: Thank you very much. 24 MS LEA: Thank you, Mr. White. 25 Sorry, I didn't hear your "Thank you". 26 Mr. Mia? No. Dr. Cronin. 27 MR. CRONIN: Yes. Good morning. 28 Let me ask a couple of questions in 809 DTE/PROBYN Panel 1 three areas. I believe -- is it Mr. Musial? 2 MR. MUSIAL: Yes. 3 MR. CRONIN: You had mentioned a 4 number of transition costs that a utility might have to 5 bear going through this restructuring. I guess I just 6 wanted to clarify. There was just a discussion now 7 about the issue of stranded costs and contestable 8 services. 9 What I wanted to clarify was whether 10 or not you were aware of the fact that for 11 restructuring related expenses the plan does have 12 provisions for utilities to collect those costs. 13 MR. MUSIAL: I'm aware, but I'm also 14 aware that the utility has suffered through this 15 process or suffered through a regulatory process for 16 recovery of those and to intervention where there would 17 be argument about what was appropriate on their part as 18 an investment. 19 MR. CRONIN: Right, but I don't think 20 we can limit stakeholders reasonable scrutiny of 21 expenditures, but the plan does provide mechanisms for 22 transition expenditures which meet the criteria to be 23 recovered by the utility. 24 MR. MUSIAL: Right, and the MEU would 25 have to be aware of that risk of loss, I guess, before 26 they embarked on any program like that. 27 MR. WHITE: Right. I guess I'm 28 trying to deal with expenditures that might not be 810 DTE/PROBYN Panel 1 subject to the kind of losses you are talking about. 2 I'm talking about hires for restructuring activities, 3 possibly upgrade system billing systems to meet 4 settlements issues, those kinds of transition costs 5 would be dealt with, well they intended they would be 6 dealt with in the proposal. I don't see that they 7 would lead to the possibility of necessarily stranded 8 costs. 9 I guess I'm trying to clarify. Are 10 you saying that the plan does not deal sufficiently 11 well with restructuring costs per se? 12 MR. MUSIAL: Yes. I think before a 13 utility might embark on incurring those transition 14 costs that it might want some assurance of the recovery 15 of those costs. It might not want to go after the fact 16 and present the bill and then be subject to a prudency 17 review of those expenses. 18 MR. CRONIN: Well, I guess the plan 19 basically suggests criteria that the utility should 20 apply those costs to judge whether or not they would 21 have an expectation. Let me ask in a second area 22 because I wanted to qualify my understanding of your 23 submission from August 12. 24 It appeared to me when I read the 25 submission, and I am speaking here about pages 4 and 5, 26 or some of page 4, I guess. Is it your understanding 27 based on the discussion in the first paragraph of 2.4 28 that the plan is proposing to apply historical changes 811 DTE/PROBYN Panel 1 in the input price index to future rate changes because 2 the paragraph describes a condition in the equipment 3 manufacturing market, suggesting that over this period 4 equipment prices were unusually flat. 5 MR. MUSIAL: I think initially when 6 we read the draft that we did view that the IPI in the 7 PBR formula would be based on a historic trend. I 8 think at this point we know now that it's going to 9 capture the single prior year. Is that correct? 10 MR. CRONIN: That's correct, and it 11 does include specifically changes in equipment prices 12 as well as other investments made by distribution 13 utilities as well as changes in wage rates and material 14 purchases. 15 MR. MUSIAL: And the base for the 16 index would be OO? 17 MR. CRONIN: I'm sorry, the base 18 would be -- 19 MR. MUSIAL: The base for the IPI 20 index would be the year 2000 then. 21 MR. CRONIN: Well, it would be the 22 prior year. Yes. 23 MR. MUSIAL: So the first adjustment 24 would occur in 01, so the base would be the year 2000. 25 MR. CRONIN: That's right. 26 MR. MUSIAL: Yes. 27 MR. CRONIN: Does that give you more 28 comfort with respect to at least that paragraph? 812 DTE/PROBYN Panel 1 MR. MUSIAL: Yes. 2 MR. CRONIN: Okay. I also wanted to 3 -- I know for participants who have not, and I am not 4 suggesting that you didn't monitor the process, but we 5 did put out a lot of paperwork, I think almost going a 6 year back. 7 We had published a report. I believe 8 the title was "PBR Options in Ontario" back last fall. 9 Also, we had put out a task force report on the cap 10 mechanism. Would you have had access to those reports? 11 MR. MUSIAL: I have them now. At the 12 time I didn't. 13 MR. CRONIN: Okay. Because in both 14 reports I believe we did talk about the issue of the 15 CPI versus the input price index. 16 MR. MUSIAL: Right. Also, if I 17 might, in the question and answer document that was 18 just recently put out, there was some discussion about 19 that. Still one of the questions, either one of the 20 MEUs or an amalgamation of MEUs, and it was synthesized 21 to this question, they still ask about, you know, 22 looking back at historic productivity factors against 23 CPI. 24 Their question was if the historic 25 had been, you know, .9 per cent, why are we now being 26 suffered to a minimum of 1.25 per cent. 27 MR. CRONIN: Right. But that is on 28 the productivity not on the input price index. That is 813 DTE/PROBYN Panel 1 the suggestion for the productivity factor. 2 MR. MUSIAL: Right. 3 MR. CRONIN: I guess all I'm asking 4 you is: When you wrote this statement were you aware 5 of the fact that we had had discussions about the CPI 6 versus the input price index? I know there was a lot 7 of material that came out. 8 MR. MUSIAL: Yes. We were. 9 I think generally our concern was 10 that -- and it appeared that there was a reliance on 11 some experience that had taken place with the U.K. and 12 with the FCC and that there was some indication that 13 there was a delta between the CPI and the IPI, the 14 producer's price index, and that that might be relevant 15 here. 16 MR. CRONIN: Yes. 17 MR. MUSIAL: I think in some of these 18 new regulatory requirements that are being requested of 19 the MEUs that that statement may not be totally true, 20 that to the extent that you have to take on these new 21 requirements your IPI may be higher than the CPI. 22 So I guess I would only suggest that 23 maybe there should be maybe a split the difference 24 between CPI and IPI. 25 MR. CRONIN: Well, because of your 26 very statement it is possible for the IPI to be higher 27 than the CPI, and in that sense if the IPI were higher 28 we would want the utilities to recover the IPI. We 814 DTE/PROBYN Panel 1 would want them to recover the full cost of the typical 2 utility's experience in the province. 3 So let me ask this: If there were, 4 as you suggest -- let's accept the hypothesis for the 5 moment that this process imposed higher procurement 6 requirements on the utilities and their IPI was higher, 7 what we are suggesting is that if all -- or if the 8 typical utility's IPI experience increases then 9 utilities have the choice of passing that through 10 without needing approval. 11 So are you less uncomfortable if in 12 fact we are basing this on the actual experience of the 13 typical utility in the province and if all utilities 14 face similar cost pressures that will be reflected? 15 --- Pause 16 MR. MUSIAL: I'm thinking of 17 Sparticus, and it seems that they are all being now 18 tossed like gladiators into the ring and being forced 19 to battle it out against each other. 20 But I guess to the extent that one 21 can minimize their IPI against another they come out as 22 a winner. 23 MR. CRONIN: That's right. That was 24 our intent, was to basically let the utilities do the 25 best they could. 26 If in fact their input prices, say 27 because of an increase in interest rates, if their 28 input prices rose even higher than the CPI, the 815 DTE/PROBYN Panel 1 proposal was that they should recoup those. 2 MR. MUSIAL: Offset them by the fact 3 that maybe the productivity -- those IPI increases 4 don't necessarily lend themselves to productivity 5 increases. 6 MR. CRONIN: No, no. They are two 7 separate issues. Yes, they are two separate issues. 8 MR. MUSIAL: But not on ROR. 9 MR. CRONIN: Well, in fact, let me 10 talk about that. Let me ask -- 11 MS LEA: Do you have further 12 questions for the presenters, Dr. Cronin? 13 --- Laughter. 14 MS LEA: I'm happy -- 15 MR. CRONIN: I do. I do. I do. 16 MS LEA: That's fine. 17 MR. CRONIN: I do. I do. 18 MS LEA: I just want to make sure 19 this is a questioning, not a debate. 20 Thank you. 21 MR. CRONIN: No, no. 22 MS LEA: It's some debate. 23 Go ahead, please. 24 MR. CRONIN: All right. 25 What Jennifer views as a debate I 26 just view as trying to -- 27 MS LEA: No, that's fine. Go ahead. 28 MR. CRONIN: -- trying to approach 816 DTE/PROBYN Panel 1 this from a research perspective. I'm a researcher, 2 not a lawyer. Even worse, I am an economist, not a 3 lawyer. 4 I hate to ask questions without sort 5 of getting into the meat of the issue. 6 We had over the past -- are you 7 aware -- I'm going to ask questions because -- 8 MS LEA: Go ahead. Go ahead, 9 Dr. Cronin, the way that you are comfortable. That's 10 the only way to do it. 11 Go ahead. 12 MR. CRONIN: I hate interrogating 13 people. 14 Over the past three days there have 15 been long discussions about this whole issue of if you 16 have made efficiency improvements are you penalized. 17 To state my bias, I and, for example, Dr. Bauer who 18 testified for the consumers group, suggested that if a 19 firm had made efficiency improvements in the past, 20 particularly if it was based on better management, that 21 firm would not be disadvantaged going forward, but it 22 is true that firms that had not made efficiency 23 improvements in the past had the ability to make those 24 unmade efficiency improvements. So I'm just stating my 25 bias on this. 26 So let me just ask: Do you agree 27 that there are at any moment in time utilities that 28 have better management teams than others? 817 DTE/PROBYN Panel 1 MR. MUSIAL: Me personally? Sure. 2 MR. CRONIN: I'm just asking, do you 3 believe that the distribution -- 4 MR. MUSIAL: I believe that is true 5 of the world in general. 6 MR. CRONIN: Thank you. 7 MR. MUSIAL: There are better 8 governments, better baseball teams. 9 MR. CRONIN: Absolutely. Right. 10 Absolutely. Absolutely. 11 Do you also agree that at any moment 12 in time there are a portfolio of choices with respect 13 to new business practices or processes or technologies 14 that could be applied to any business including the 15 utilities? 16 MR. MUSIAL: Sure. 17 MR. CRONIN: So that would you also 18 agree that if a firm had demonstrated over some period 19 of time, whatever we want to choose, three, five or ten 20 years, if that utility's management had demonstrated a 21 higher ability to react to these changes in technology 22 practices or processes, would you believe that they 23 would continue to react to new opportunities and 24 practices processes and technology? 25 MR. MUSIAL: Can I ask you, is that 26 going to be your last question? 27 --- Laughter 28 MR. CRONIN: Absolutely. 818 DTE/PROBYN Panel 1 MR. MUSIAL: Because I could -- 2 MR. CRONIN: Yes, that is my last 3 question. 4 MR. MUSIAL: I do believe it. I do 5 believe that -- I mean, that's the reason why we picked 6 companies to invest in, right, because we looked at 7 their past practice and we believe that they are going 8 to be able to carry that forward, or why we would pick 9 any -- and I believe that efficient management will 10 continue to be efficient. 11 But I also -- and I'm not an 12 economist, forgive me, but I have heard this concept of 13 law of diminishing returns -- I know that kind of works 14 in my household economic situation -- and so I do think 15 that this is not linear. I do think that at a point 16 for any investment you are going go get diminished 17 productivity. 18 MR. CRONIN: Could I make a 19 suggestion, that that law of diminishing returns 20 typically assumes that you have a static environment 21 and that you don't have the opportunity to draw from 22 these new opportunities. 23 But I would agree totally with your 24 statement and the intended proposal was not to penalize 25 these efficient utilities but to provide opportunities 26 for them to continue to flourish. 27 I really enjoyed your presentation. 28 Thank you. 819 DTE/PROBYN Panel 1 MS LEA: Thank you. 2 Ms Kwik, you have questions? 3 MS KWIK: Yes. 4 I would like to start by expressing 5 my gratitude for the efforts that you put into 6 providing us with detailed comments on the service 7 quality, I do appreciate them. 8 What I would like to ask is: Do you 9 feel that the Board should be able to compare the 10 performance of the distributors in Ontario in terms of 11 service quality with distributors in other 12 jurisdictions? 13 MR. ALLEN: Yes. 14 I guess I will offer the comment that 15 I think that is why we tried to separate that you may 16 still want to measure everything that is in your table, 17 it is just will the distribution utility be accountable 18 for to the Board. By having those types of measures in 19 place then we can compare statistics on a national and 20 international basis on how well they perform. 21 But I think our comments were really 22 on the separation that now we code the events slightly 23 differently and then for Board reporting purposes we do 24 that separation. 25 So we thought it was very important 26 from -- the current view is really from the total 27 customer point of view of how efficient is the system, 28 yet you need to look at who is responsible for each of 820 DTE/PROBYN Panel 1 those measurements. 2 MS KWIK: Thank you for that 3 explanation. 4 Another thing you did suggest was 5 that with the utilities being at different points of, I 6 guess sophistication in being able to record some of 7 these service quality standards, that there is a lack 8 of a level playing field at the start. How do you 9 suggest we should address that so that there is a level 10 playing field? 11 MR. BABAIE: Well, I guess linking to 12 your earlier question, you talked about benchmarking 13 with another number of jurisdictions, the issue here 14 is, number one: What is the objective here? Is the 15 objective here to motivate MEUs to improve their 16 performance, their operations, add more to its 17 efficiencies, or the objective here is basically only, 18 you know, just policing them and their performance? 19 If it is the earlier, you know, the 20 objective is valid, move valid than the second one, 21 then I guess the notion is that you need to basically 22 use the previous information for only statistical 23 information then establish a base in terms of the time 24 frame, whether it is the year 2000 or whatever you want 25 to -- you know, to consider that. 26 From that perspective I guess this 27 first generation of the PBR is only the collection and 28 then basically that gives an opportunity for the MEUs 821 DTE/PROBYN Panel 1 on the second generation of the PBR basically to be 2 measured based on apples to apples. 3 MS KWIK: Thank you. 4 With regard to the unbundling of the 5 rates, you pointed out that some of the load data that 6 we are suggesting you can use is from the 1980s, a 7 little outdated. How long do you think it would take 8 us if we wanted to update that research, load data 9 research, to make it satisfactory? 10 MR. MUSIAL: It's a tough question 11 for me to answer. I don't know. 12 MR. ALLEN: I think -- I don't know. 13 I think there are a number of 14 different approaches. The one, if you are trying to do 15 it on the whole provincial basis I think some of it is 16 going to be almost impossible to do because much of 17 that data isn't recorded. 18 I think on a statistical sampling 19 basis now there is ways and means of putting technology 20 in place to actually start recording those types of 21 statistical sample. 22 I think that type of information 23 gathered from across all of the MEUs and brought back 24 to the Board to say here is what we will call what our 25 standard customer and our standard profile is and do it 26 on a real time basis, so take some northern communities 27 that we need ex-number of residential customers with 28 the various different type of mixtures of load. I 822 DTE/PROBYN Panel 1 would think rather than trying to recreate what is 2 there setting up a means for the Board to actually 3 gather real time data would give you a means and then 4 assuming that type of data -- my belief is the Board is 5 going to require that on an ongoing basis, so I think 6 different ways of picking, I don't know, maybe a couple 7 of hundred sample customers to give you that real time 8 input would be far more effective than trying to go 9 back and sit through the records of incomplete data. 10 MS KWIK: In that minimum how long 11 would we have to sample that information for to 12 establish a base for doing the unbundling? Would you 13 want to cover the four seasons? 14 MR. MUSIAL: Yes, I think we would 15 need a minimum of one year. Preferably you would have 16 at least two cycles to go through that and then you 17 could compare that with the historic. 18 Again, I think by setting up the 19 means of doing that and requiring it on an ongoing 20 basis then the Board would have a way, a means, to 21 adjust as technology from the consumer end changes on 22 different uses of load patterns and rather than having 23 this long lag of -- the best data we have got is at 24 least 10 years old and what is in our houses today is 25 much different than what was in our houses 10 years 26 ago. 27 MS KWIK: Okay. Thank you. 28 MS LEA: Thank you. 823 DTE/PROBYN Panel 1 Any other questions for these 2 gentlemen? 3 If not, I would like to thank you 4 very much for your attendance here at this technical 5 conference. We really appreciate your presentation and 6 the assistance you have given the Board with this. 7 Thank you. 8 MR. ALLEN: We thank the Board very 9 much for the opportunity. 10 MR. BABAIE: Thank you for the 11 opportunity. 12 MS LEA: Mr. Gibbons, are you ready 13 to proceed with your presentation? 14 --- Pause 15 MS LEA: Thank you, Mr. Gibbons. I 16 think that the reporters already have your spelling of 17 your name, so please go ahead. 18 PRESENTATION 19 MR. GIBBONS: Thank you. 20 I am here on behalf of Pollution 21 Probe. The Board staff's handbook proposes price cap 22 regulation for Ontario's municipal electric utilities 23 and under price cap regulation a utility can increase 24 its profits fundamentally in two ways, one by 25 increasing its sales and second by reducing its cost. 26 Now, energy efficiency programs on 27 the other hand, of course, reduce sales and therefore 28 reduce revenues and also revenue efficiency programs 824 Pollution Probe Panel 1 will increase costs. So if a municipal electric 2 utility promotes energy efficiency, everything else 3 being equal, the price cap regime will financially 4 penalize the utility shareholder because sales go down, 5 revenues go down, profits go down, and also costs go up 6 which also reduce profits. 7 So this proposal which penalizes 8 utilities from promoting energy efficiency is -- in our 9 opinion it is inconsistent with the Ontario Energy 10 Board Act, it is inconsistent with the Board's 11 rate-making principles for gas utilities and it is 12 inconsistent with the public interest in general. 13 First, with respect to the 14 inconsistency with the Ontario Energy Board Act. The 15 Ontario Energy Board Act now says for the first time 16 that one of the objectives of the Ontario Energy Board 17 is to promote energy efficiency. So now it is clearly 18 inappropriate for the Board to come forward with a PBR 19 mechanism that flies in the face of that objective. 20 In terms of inconsistency with the 21 Board's regulation of Ontario's gas utilities the Board 22 has established a PBR mechanism for Enbridge Consumers 23 Gas which removes any disincentives to Enbridge 24 Consumers Gas' shareholders for the promotion of energy 25 efficiency and is also a shared savings mechanism which 26 links Enbridge Consumers Gas' profits to their success 27 at reducing their customer's bills through energy 28 efficiency. 825 Pollution Probe Panel 1 As a result of that mechanism I 2 believe that for the Enbridge Consumers Gas year that 3 we are in now, fiscal year, Enbridge Consumers Gas 4 because of its excellent performance in reducing 5 customers bills will be eligible for a bonus, I 6 believe, of approximately $3 million. 7 Now, we have got this mechanism for 8 Enbridge Consumers Gas which serves customers in 9 Toronto and elsewhere in Ontario and then if this 10 mechanism was to go ahead, other utilities, electric 11 utilities serve the same customers. If they reduce a 12 customer's bill they are financially penalized whereas 13 when Consumers Gas does it is financially rewarded. 14 That is inconsistent regulation. It is unfair and it 15 is economically irrational. 16 Penalizing Ontario's municipal 17 electric utilities is also inconsistent with the public 18 interest for at least three reasons. 19 First, energy conservation programs, 20 energy efficiency programs, can reduce customers bills 21 and very significantly and bill reductions are good for 22 customers. Union Gas and Enbridge Consumers Gas have 23 developed energy efficiency programs which will reduce 24 their residential, commercial and industrial customers' 25 bills by over $400 million. 26 Those energy efficiency programs make 27 the residential customers better off. They make the 28 commercial customers and the industrial customers more 826 Pollution Probe Panel 1 competitive. That makes the Ontario economy more 2 competitive and leads to more jobs. Of course, I mean, 3 that was one of the main objectives of the whole 4 electricity restructuring was to make our economy more 5 competitive and to create jobs. 6 Finally, energy conservation programs 7 are in the public interest because they reduce air 8 pollution. Reducing air pollution is very important 9 for a couple of reasons. 10 We have a very serious air pollution 11 problem in this province. The Ontario Medical 12 Association has declared that air pollution is a public 13 health crisis in the province of Ontario and the 14 electricity sector is a major contributor towards that 15 air pollution public health crisis. 16 Ontario Power Generation company is 17 the largest corporate source of nitrogen oxide 18 emissions, mercury emissions, and mercury is a very 19 potent neurotoxin, and carbon dioxide emissions. 20 Ontario Power Generation is also the largest, second 21 largest, corporate source of sulphur dioxide emissions. 22 So another big bonus of energy conservation programs is 23 they reduce air pollution and protect public health in 24 the environment. 25 So Pollution Probe's recommendation 26 as to how to deal with this problem, at least for the 27 first generation of PBR programs, is to make a 28 modification to the PBR Rates Handbook where the Board 827 Pollution Probe Panel 1 would encourage municipal electric utilities that want 2 to undertake energy efficiency programs to reduce their 3 customer bills to apply for PBR DSM incentives. It has 4 two characters. 5 First, incentive mechanisms or 6 regulatory mechanisms will ensure that there is no 7 financial penalty for a municipal electric utility for 8 promoting energy efficiency and second, an incentive 9 mechanism that will actually financially reward the 10 municipal electrical utility for aggressively and cost 11 effectively promoting energy efficiency, because in our 12 experience in Ontario and also the experience 13 throughout North America is if you really want these 14 electric utilities to aggressively and cost effectively 15 promote energy efficiency you can't just remove the 16 disincentives but you have got to create a positive 17 profit incentive for them to do that. Once you create 18 that positive profit incentive great things happen for 19 the customer. 20 Thank you. Those are my opening 21 submissions. 22 MS LEA: Thank you, Mr. Gibbons. 23 Questions for Mr. Gibbons. Mr. 24 Rodger? 25 MR. RODGER: No. Thank you, Ms Lea. 26 MS LEA: Mr. Grieve? 27 MR. GRIEVE: Yes, just a couple of 28 things. Would you agree with me that the impact of 828 Pollution Probe Panel 1 artificially low costs in electricity due to the 2 exclusion of contributed capital from the PBR handbook, 3 as we have been discussing at length over the last few 4 days, that the impact of that is to be a disincentive 5 to energy efficiency efforts. 6 MR. GIBBONS: I'm sure anything that 7 lowers the price of electricity is a disincentive to 8 energy conservation. The higher the price, the greater 9 will be the incentive to conserve electricity. 10 MR. GRIEVE: Any recommendation on 11 that front? 12 MR. GIBBONS: In terms of contributed 13 capital? 14 MR. GRIEVE: Yes. 15 MR. GIBBONS: No. That is sort of 16 beyond the mandate of Pollution Probe, and I certainly 17 haven't investigated that in a detailed way to give an 18 expert opinion. I mean, I have sat through this 19 hearing or this procedure for the last few days and I 20 have heard the different views, but I can't give an 21 expert opinion. 22 Clearly, though, if contributed 23 capital was included in rate base, rates, everything 24 else would be higher and that would promote 25 conservation. 26 MR. GRIEVE: Thank you. 27 MS LEA: Thank you. 28 Mr. White. 829 Pollution Probe Panel 1 MR. WHITE: I have one question and 2 that is: With your suggested implementation of an 3 energy conservation incentive program for MEUs and the 4 Ontario Hydro Services Company, would you suggest that 5 the costs and the revenues and the bonuses be hived off 6 from the rest of the normal accounting handling with 7 the utility and treated as a discrete financial 8 program? 9 I think that is what I heard in your 10 comments. 11 MR. GIBBONS: I'm not sure what you 12 mean when you are talking about "hived off". I mean, 13 certainly it will be important for the utility to 14 record what its DSM costs were and the revenue impact 15 of that. That will be important. If that is what you 16 mean by "hived off", I agree. 17 MR. WHITE: What I mean is from a 18 regulatory point of view that those dollars, costs and 19 revenues be treated in some way very specifically and 20 discretely from the rest of the normal utility 21 operations. 22 MR. GIBBONS: One, I think there 23 should be proper accounting so we know how much we are 24 spending on DSM and whether we are getting our money's 25 worth from the utilities. 26 But to say that in a way that is 27 different from the normal operations of the utility, I 28 see this as part of the core operations of a 830 Pollution Probe Panel 1 distribution utility and I don't see this as some kind 2 of a fringe activity but a fundamental part of a 3 distribution utility ensuring that its distribution 4 system is of the correct size and we don't make 5 excessive investments in terms of electricity 6 distribution infrastructure when DSM could meet the 7 customer's energy service needs at a lower cost. 8 MR. WHITE: I think you and I aren't 9 going in separate directions. I think what is really 10 important is that the costs and the revenue impacts be 11 tracked so that the true benefits and costs can be 12 measured. 13 Thank you. 14 MR. GIBBONS: I absolutely agree. 15 MS LEA: Thank you, Mr. White. 16 Mr. Mia? Thank you. 17 Dr. Cronin, Ms Kwik? 18 MR. CRONIN: I will go after Ms Kwik. 19 MS LEA: Certainly. Go ahead, 20 please. 21 MS KWIK: If you take into 22 consideration that the distribution component of a 23 customer's total bill for electricity is approximately 24 15 per cent, do you think making the -- 25 MS LEA: Ms Kwik, was that 50 or 15? 26 MS KWIK: Fifteen. 27 MS LEA: Thank you. 28 MS KWIK: -- do you think making the 831 Pollution Probe Panel 1 distributor responsible for carrying out the DSM 2 programs might increase their rates significantly? 3 MR. GIBBONS: I think it is extremely 4 unlikely to increase their rates significantly. 5 I mean, if you look at the gas 6 utilities with the same situation where the 7 distribution cost is a minor part of the total cost, 8 the bigger part is the gas commodity and the 9 transmission costs from Western Canada and, certainly 10 in terms of the gas utilities, the rate impacts have 11 been trivial. I mean, I haven't refreshed that rate -- 12 the rate impact question came up yesterday. I think it 13 was Dr. Cronin who asked Mr. Chernick about rate 14 impacts, and I haven't had a chance to go back to my 15 office since then. 16 But my recollection of the gas 17 utilities, the rate impacts were always less than 1 per 18 cent, significantly less than 1 per cent. 19 I know when we had the gas DSM 20 generic hearing back many years ago, people raised this 21 question: Would the rate impacts be significant? But 22 since they have been implemented they have always so 23 small that it has never been an issue in the hearing 24 and the bill impacts have been so much greater. 25 So that hasn't been an issue. 26 Again, what we are talking about is 27 creating the right incentive mechanisms for the 28 utilities. We are not talking about the OEB or 832 Pollution Probe Panel 1 Pollution Probe coming to the utilities saying, "You 2 must do this or that". The onus will be on the utility 3 to respond to the incentive mechanism if they want. 4 Now, the utility will bring forward 5 what they think is appropriate and no municipal 6 electric utility is going to bring forward a DSM 7 program that would have unacceptable rate impacts. I 8 mean, why would they do that? 9 MS KWIK: If it is left to the 10 utility to make the proposal, do you think there ought 11 to be some consistency for all of the utilities in 12 terms of the responsibility they have with regard to 13 DSM? 14 MR. GIBBONS: I mean, consistency is 15 a good principle, but applying exactly the same 16 principles to utilities which are in very different 17 circumstances I don't think makes good public utility 18 regulation. 19 I mean, we have some utilities like 20 Toronto Hydro which are amongst the largest utilities 21 in the country, and we have lots of utilities here with 22 only one or two employees. To treat them the same when 23 they are totally different, fundamentally different, 24 doesn't make any sense. 25 Again, when we went forward with gas 26 DSM, the Board didn't treat all gas utilities in 27 Ontario the same. At the time, there were three major 28 gas utilities in Ontario and those were the ones that 833 Pollution Probe Panel 1 were required to do DSM, but there were a number of 2 other gas utilities which were very small and the Board 3 imposed no DSM obligations on them just because it's 4 not pragmatic, it's not practical for a very small 5 utility to cost-effectively deliver DSM. 6 I mean, one of the fundamental points 7 of DSM is to reduce customers' bills and certain 8 utilities who are too small can't do that through DSM. 9 MS KWIK: Mr. Chernick mentioned 10 yesterday too that there was going to be the need to 11 bring distribution utility employees up to speed, I 12 guess, on their expertise on DSM. 13 Do you think this involves an issue 14 in terms of introducing the programs, the timeliness of 15 introducing programs? 16 MR. GIBBONS: Sure. A utility, if it 17 is going to come forward with a DSM program for Board 18 approval, I mean it will obviously have to have staff 19 in place who can deliver those programs 20 cost-effectively. But, again, that is the issue for 21 those utilities. It is their job to manage their 22 companies and I'm sure they won't come before the Board 23 until they think they can deliver these programs 24 cost-effectively. 25 So I think really the role for the 26 Board in this sort of more market-oriented world we are 27 moving into is to create the right incentives for the 28 utility so that to the largest extent possible the 834 Pollution Probe Panel 1 utility's financial self-interest is aligned with the 2 overall public interest and then allow the utilities to 3 manage their own business and come forward with 4 proposals. 5 MS KWIK: Thank you. 6 MS LEA: Dr. Cronin, you were next? 7 MR. CRONIN: Yes. 8 I just wanted to clarify one issue 9 and then maybe talk about some of the things that we 10 had a chance to talk with Mr. Chernick about yesterday. 11 In your dialogue with Mr. Grieve -- 12 is it Grieve? 13 MR. GRIEVE: Grieve, yes. 14 MR. CRONIN: -- you had talked about 15 the relationship between the price of electricity and 16 conservation and I think said something to the effect 17 of the higher the price of electricity the more 18 conservation we would induce. 19 You are not suggesting that there be 20 a non-optimal price of electricity from a true cost 21 perspective just to pursue more conservation? 22 MR. GIBBONS: Absolutely not, sir. 23 I'm an economist. I believe that ideally the price 24 should equal the long-run marginal cost. 25 MR. CRONIN: Right. Okay. 26 I noted in your submissions that you 27 dealt with a couple of the areas that we were talking 28 about yesterday in that you did discuss the problem 835 Pollution Probe Panel 1 with the very large number of small utilities. 2 MR. GIBBONS: Right. 3 MR. CRONIN: Do you have any thoughts 4 on the issue of some kind of regional organization or 5 agent that could act as a co-ordinator or implementor 6 for DSM because of this issue of small utilities? 7 MR. GIBBONS: Yes. I mean, 8 certainly, I think -- like the small utilities I 9 believe, in terms of procuring electricity, will be 10 going with some kind of regional aggregator, for 11 example, maybe ENERconnect. That is something that the 12 municipal utilities I believe are doing on their own 13 initiative because it is the best way they can meet 14 their customers' energy service needs. I would see if 15 there was a DSM incentive and they might be motivated 16 to, through ENERconnect or some other aggregator of 17 DSM, do the same thing. 18 I mean, that would be my main 19 message. I really think the important thing for the 20 Board is to create the right incentives, put the right 21 incentive structure out there and then leave it up to 22 the creativity of the market to try to figure out the 23 best way to respond. 24 MR. CRONIN: Okay. 25 Also, with respect to this issue 26 of -- and I think you talked about some of these in 27 your statement -- the broader issues of DSM which 28 really cut in some sense across all aspects of 836 Pollution Probe Panel 1 electricity and many other forms of energy, is there 2 a -- I mean, how would you suggest that the Board or 3 government approach that aspect of the problem? In 4 other words, as I understand it, the Board does not 5 regulate the generation or -- 6 I guess I'm asking: How would the 7 Board best deal with the breadth of the problem in 8 terms of multiple energy sources, not just gas and 9 electric? But even among gas and electric there are 10 different aspects to the industries. 11 MR. GIBBONS: Right. The Ontario 12 Energy Board has a mandate, but it certainly isn't able 13 to solve all our energy problems. It has a specific 14 mandate. 15 I think, you know, a major part of it 16 is regulating natural monopolies. When it regulates 17 natural monopolies, be it gas or electric, I think it 18 should create incentive structures to make them what do 19 what's in the overall public interest. Part of that is 20 promoting energy efficiency and making sure that we 21 don't spend too much on the gas or electricity supply 22 side infrastructure when DSM could meet those energy 23 service needs at lower costs. 24 That's what's part of the core 25 mandate of the Ontario Energy Board. Through that, 26 that policy instrument, it can't solve all the energy 27 problems, energy efficiency problems or all the 28 environmental problems. I think, you know, we should 837 Pollution Probe Panel 1 focus on what it can do. 2 There are other agencies of 3 government that can deal with some of the other ones. 4 For example, in terms of dealing with public health and 5 environmental problems, I mean there's a major problem 6 of the coal fired power plants. 7 Energy efficiency programs partly 8 address that by reducing the demand for electricity, 9 but that's not going to solve all the problems. There 10 is also the need for emissions caps on the coal fired 11 power plants, but that's way beyond the role of the 12 Ontario Energy Board. That's something for the 13 Ministry of the Environment to deal with. 14 I don't think we should expect the 15 Ontario Energy Board to solve all our problems, but 16 just solve the ones that are clearly within its 17 legislative mandate. The legislature has recently 18 given a mandate to promote energy efficiency with 19 respect to the natural monopolies it regulates. Just 20 do that role. That's not going to solve all Ontario's 21 problems, but if the OEB could do that role well and 22 its other roles well, it will make a contribution, an 23 important contribution. 24 MR. CRONIN: And, finally, I take it 25 in your submission that you are recommending that the 26 Board include a broader overview of DSM in the mid-term 27 review for -- 28 MR. GIBBONS: Absolutely, yes. 838 Pollution Probe Panel 1 Hopefully for the mid-term review, at least the second 2 generation of DSM, the Board can review what's happened 3 to date and dialogue with stakeholders and come forward 4 with new rules for the second generation PBR scheme 5 hopefully even better than what we are going to get for 6 the first generation if the Board accepts Pollution 7 Probe's sort of interim stopgap solution. 8 MR. CRONIN: Thanks. 9 MS LEA: Thank you. Any other 10 questions for Mr. Gibbons? 11 Seeing none, thank you very much, Mr. 12 Gibbons, for your attendance here today and your 13 presentation and also for your participation throughout 14 the technical conference. 15 MR. GIBBONS: Thank you. 16 MS LEA: Thank you. 17 Mr. White, are you ready to proceed? 18 MR. WHITE: Yes. 19 MS LEA: Thank you. Please come 20 forward. 21 Mr. White, I have been given a copy 22 of what I presume is a summary of your presentation, a 23 written copy of your presentation, is that right? 24 MR. WHITE: Yes. There were other 25 copies available. 26 MS LEA: There are other copies 27 available. Great. 28 Can we mark that as Exhibit F, 839 1 please. 2 EXHIBIT F: Summary of 3 Presentation of Mr. White 4 MS LEA: Please go ahead, sir. 5 PRESENTATION 6 MR. WHITE: Energy Cost Management 7 Incorporated in these proceedings is representing eight 8 municipal utilities, seven of which prior to their 9 recent expansions and even subsequent to their recent 10 expansions would have been classified or would be 11 classified as small distributors in the Board's 12 definition of 10,000 customers. 13 One of our clients prior to its 14 expansion would have been probably classified as a 15 micro utility in terms of the marketplace, so I think 16 the perspective we bring is one that not only has 17 concern for customers, but a recognition of the broad 18 spectrum of utilities in Ontario. 19 We would like to open our comments by 20 confirming that it is the intent of ECMI to make a 21 positive contribution to this review process on behalf 22 of our clients. We recognize that the industry is in a 23 time of significant change and that there is a need to 24 recognize the interests of all stakeholders, customers, 25 LDCs and shareholders in the process. 26 Our primary focus will be on the 27 broad technical aspects of the PBR handbook and some 28 areas of specific interest to some 10 per cent of the 840 ECMI Panel 1 utilities in Ontario. What I would like to do today is 2 to hit the high points of our previous submissions. 3 All of our clients have recently 4 acquired facilities from OHSC. Because Ontario Hydro 5 did not maintain records specific to the areas acquired 6 by our clients, I was encouraged to hear the Board's 7 consultants and I think Board staff concur with our 8 view that our client's submissions for approval should 9 be based on best estimates of what the base period for 10 PBR regulation would have imposed had the information 11 been available. 12 Contributed capital. It has been 13 pointed out by Board staff consultants on a number of 14 occasions and by the Board staff that utilities are not 15 compelled to earn the maximum return permitted under 16 the PBR handbook guidelines. The ECMI agrees that its 17 clients should be permitted to include the full market 18 value return on contributed capital on its books in the 19 rate base at the time the market opens or at year end 20 1999, the base period. 21 If the Board feels the need to 22 differentiate the contributed capital into historical 23 contributed capital versus going forward contributed 24 capital, we can certainly understand that. If you need 25 to differentiate the historical contributed capital in 26 terms of components in the rate base, we would ask that 27 you look at the regulatory criteria that applied to 28 municipal electric utilities prior to the change in 841 ECMI Panel 1 regulatory responsibility. 2 That criteria, in the absence of the 3 working capital constraints, allowed the municipal 4 electric utilities to earn a return that was in fact 5 below what would be classified as a fair market return, 6 but something that reflected the marginal long term 7 cost of debt for the municipal utilities. 8 If that average number were used, it 9 would serve what I think I heard to be the goals of 10 having one number and leaving the utilities no worse 11 off than they were under the previous regulatory 12 regime. 13 Utilities choosing not to go to the 14 price cap cannot currently accrue unrealized revenue 15 for future regulatory considerations. We would suggest 16 that a revision to the PBR handbook to provide a 17 mechanism for unrealized revenue carry forward. This 18 would produce a more stable price regime and also not 19 disadvantage those utilities that are less aggressive 20 in their pricing policy during the transition period. 21 With respect to the level playing 22 field, once again I was encouraged to hear that the 23 Board's consultants concur with our view that the 24 performance measures regarding customer outages should 25 include account of all users downstream from the 26 interruption. 27 Connection of new services. 28 Performance measures related to the connection of new 842 ECMI Panel 1 services should reflect a connection to existing lines 2 with adequate capacity only. It may be unrealistic to 3 expect connection performance based on a standard that 4 has been created for relatively high density urban 5 utilities when compared to rural or remote community 6 situations. 7 Cost of service study. We agree that 8 there are significant potential benefits that could 9 flow from a simplified pricing model. However, it is 10 our understanding that any departure from the draft 11 pricing regime will trigger the requirement for a full 12 cost of service study, the cost of which will be 13 onerous, and the timing insufficient to complete a 14 defensible study. 15 It is apparent that the pricing model 16 in the draft PBR Handbook, as a minimum, requires 17 increased flexibility without the imposition of a full 18 cost service study. 19 Rate impacts. The proposed version 20 of the PBR handbook assumes that existing approved 21 rates are in total an absolute compliance with the 22 model used by Ontario Hydro and the MEA, and that all 23 utilities are similar. Neither one of theses 24 assumptions is correct. 25 Utilities vary considerably in 26 customer density. In many existing approvals the 27 pricing structure recognizes that customer utilization 28 patterns can impact on losses and distribution costs 843 ECMI Panel 1 and that it is appropriate to reflect those prices -- 2 those differences in pricing. 3 Fixed or incremental losses in 4 distribution costs associated with sparse end use and 5 low annual consumption are higher than normal for 6 residential and, in fact, for all customer classes. 7 Residential rates in place today 8 reflect the cost of servicing customers at various 9 densities. The proposed rate structure appears to 10 collapse these rate structures and introduce a single 11 service charge/energy charge rate for the utility. 12 This requirement would cause a significant cost 13 transfer between customers within the class. 14 Variation in losses shift costs to 15 and from the residential service charges. A 16 calculation for a utility with losses historically 17 around 8 per cent using the PBR Handbook rationale 18 yielded an over 80 per cent loss component for the 19 incremental distribution cost. 20 Simply stated, this assumes that 80 21 per cent of the cost of distribution in the utility is 22 due to losses. 23 Assuming that to be true, one could 24 certainly argue that there is an incentive to reduce 25 losses; however, this assumes that the utility has the 26 control or ability to do so. Such is not the case for 27 all utilities. 28 The incentive to reduce losses does 844 ECMI Panel 1 not correlate with the ability to do so. 2 This is typical for utilities which 3 expanded to include a large rural component. In 4 reality, some distribution systems have inherently 5 higher losses and there is a limited opportunity to 6 recover these costs in the proposed handbook other than 7 through an increased service charge. The result of 8 this is to take costs which are largely variable in 9 nature and impose them in the fixed charge. 10 It is accepted that the 6.2 mil as 11 used in the IDC was included in the residential end 12 rate test by Ontario Hydro. The test was a floor test 13 for residential end rate and on average utilities were 14 in excess of the test level by 3 per cent. If the 15 3 per cent were translated to form part of the IDC, it 16 would require and increase in excess of 30 per cent in 17 the IDC base value. 18 With respect to the general service 19 boundary issues, the existing structure provides a 20 smooth transition for customers whose demand increases 21 below 50 kilowatts to above 50 kilowatts; however, the 22 imposed structure effectively creates two classes with 23 independent pricing structures. The unbundling process 24 does not itself preclude a smooth transition across the 25 50 kilowatt demand level. 26 We would suggest that blocking both 27 the IDC energy component and the IDC demand component 28 to achieve a smooth transition with appropriate 845 ECMI Panel 1 economic signals across the full band of consumption 2 ranges of the general service class. 3 With respect to the minimum bill for 4 large customers requiring expansion of the system, the 5 proposed scheme does not appear to contemplate recovery 6 of a cap of capital currently covered by the 7 application of the minimum bill. 8 The service charge component will not 9 probably be sufficient to ever recover capital outlays 10 for large customers. 11 In final, I would like to talk to the 12 debt factors influencing the cost of capital component 13 in the IPI. 14 The proposed structure gives a mixed 15 signal to LDCs. On the one hand it uses the Canadian 16 long-term cost of money, but then revises it annually. 17 This is a short-term signal -- I'm sorry, this 18 short-term signal suggests that a short-term cost of 19 money might be appropriate for the index. However, the 20 Board consultants rightly point out that the LDC 21 capital use decisions are generally long term. 22 To the extent that the Board may 23 impose time constraints on the use of capital by LDCs 24 through a possible combination of CX or connection 25 performance measures, then the results may lead the 26 LDCs with little discretion as to when capital is 27 invested. It, therefore, seems appropriate to only put 28 the shareholder or the utility at risk for the 846 ECMI Panel 1 long-term debt that it places or fails to place 2 relative to the imputed capital structure proposed in 3 the PBR Handbook. 4 This will lead to more stable energy 5 prices, at least the distribution component of the them 6 over the long-term, assuming that the debt is placed on 7 an arm's length basis. 8 Thank you very much. That is our 9 comments. 10 MS LEA: Thank you very much, Mr. 11 White. 12 Questions for Mr. White. 13 Mr. Rodger? 14 MR. RODGER: No, thank you. 15 MS LEA: Mr. Grieve? 16 MR. GRIEVE: No, thank you. 17 MS LEA: Anyone else? 18 Dr. Cronin? 19 MR. CRONIN: Is this the end of the 20 day? 21 MS LEA: You can take all the time 22 you like, Dr. Cronin. 23 I have a few comments of an 24 administrative nature I should make before people 25 leave, but go ahead, please. 26 MR. CRONIN: In the last section of 27 your statement when you were talking about the cost of 28 capital, I take it you do agree that the cost of 847 ECMI Panel 1 capital should be reflected in the rate adjustment 2 mechanism for utilities? 3 MR. WHITE: Yes. 4 MR. CRONIN: However one, I guess, 5 could debate how you will reflect that in that index, 6 but it is important to reflect the capital 7 particularly? 8 MR. WHITE: Absolutely. 9 MR. CRONIN: Would you also agree 10 that it should, in fact, reflect the other 11 utility-specific costs that they bear in running their 12 operation? 13 MR. WHITE: Yes. 14 MR. CRONIN: That is labour? 15 MR. WHITE: Yes. 16 MR. CRONIN: So in general you are in 17 favour of the IPI approach? 18 MR. WHITE: I can answer that 19 question with two different answers. 20 One, from a personal perspective, I 21 understand the effort and the energy that has gone into 22 producing a truly industry sensitive index and I think 23 that probably is -- from a technical perspective I am 24 comfortable with the concept. 25 From an understandability perspective 26 for my clients and certainly their customers, the 27 visibility of the Consumer Price Index or other kind of 28 measure like, it certainly would produce probably a 848 ECMI Panel 1 higher level of comfort, although I'm not convinced 2 that the unbundling of the electricity industry was 3 designed to produce comfort for anyone. 4 MR. CRONIN: I agree. The IPI should 5 mitigate their risk. 6 MR. WHITE: Right, right. I think 7 technically it's probably a more sound approach. I 8 would like to be able to pursue the determination 9 underpinning of the data based on an evaluation of the 10 "confidential data". I don't want to go there, but I 11 would like to be able to get in behind the numbers a 12 little bit more than I have been able to. 13 MR. CRONIN: Thank you very much. 14 MS KWIK: You state that the 6.2 15 mills used for the IDC that we pursue that. In fact, 16 all utilities were at that level but that in fact some 17 of them were above the residential end rate so that 3 18 per cent translated to form part of the IDC -- 19 MS LEA: I'm sorry, I can't hear you, 20 Ms Kwik. 21 MS KWIK: Would require an increase 22 in excess of 30 per cent in the IDC. Is there a 23 comment that you wanted to make on how we should 24 address if you were addressing this as an issue or are 25 you just trying to point out in fact there will be 26 differences or there should be differences in the 27 utilities IDC level? 28 MR. WHITE: Okay. I think what that 849 ECMI Panel 1 demonstrates is that the existing pricing structure has 2 a much higher variable component which may in fact more 3 realistically reflect what the current day IDC costs of 4 distributors are. 5 When I am marrying that concern with 6 the concern for customer impacts on rate design, it 7 drives me to the conclusion that if we don't want the 8 phone lines between Toronto and the rest of the world 9 in Ontario to burn to the ground, we need to carefully 10 manage the level of emphasis that flows into the 11 service charge as opposed to being left in a variable 12 component. 13 I am even prepared to recognize that 14 in the long term you may want to use such things as the 15 5 per cent mechanisms in the PBR handbook to move a 16 greater emphasis, where appropriate, to the service 17 charge component. 18 My suggestion is that in the front 19 end, if you apply this to all utilities universally, 20 the outcomes are going to be inconsistent and not 21 understood by either utilities or customers. 22 I think from the inconsistency that 23 will be created by the application of the rules in the 24 PBR handbook, it may challenge the very credibility of 25 the regulatory process as well as the unbundling of the 26 energy market. 27 MS KWIK: You also highlight the fact 28 and in fact we had omitted the minimum bill provision 850 ECMI Panel 1 in the draft rate handbook. Have you any suggestions 2 on how that might be approached? 3 MR. WHITE: My preference -- is the 4 microphone cutting out periodically? Okay. I thought 5 it was maybe me. 6 My preference would be to see 7 probably a contract concept that would operate to 8 complement whatever CIAC regime the Board puts in 9 place. 10 Contributions in aid of construction 11 to the extent that they are taken associated with a 12 major capital investment by a distribution utility may 13 not be protected by a minimum bill contract provision, 14 but I think certainly over a minimum period of time and 15 maybe in part, depending upon the level of risk that's 16 in place with respect to a facility that were going to 17 be constructed, in other words, that there's a 18 likelihood that the facility would be used for other 19 customers in the near term, then maybe a five year 20 contract with appropriate bonds and guarantees to 21 protect that kind of capital investment would be 22 appropriate to protect both the shareholder and the 23 other customers within the LDC. 24 MS KWIK: Thank you. 25 MS LEA: Thank you. 26 Any other questions for Mr. White? 27 If not, Mr. White, thank you very 28 much for your attendance here, for your presentation 851 Preliminary Matters 1 today and for your participation throughout the 2 technical conference, your assistance to the Board. 3 Two matters then before we close. 4 First, in the morning break I received confirmation 5 that the Board has issued a letter dealing with the 6 motion filed by Mr. Power on behalf of his client. 7 This letter is dated September 23 and 8 I believe it was sent out by Purolator to intervenors 9 in this proceeding, that is to all intervenors. 10 The letter indicates in brief that 11 the Board is determined that it will not hear the 12 motion. The reasons for that are set out in the 13 letter. 14 Any parties who wish a copy of this 15 letter and who are not intervenors in this proceeding, 16 perhaps you could contact myself or Board staff to get 17 a copy because I think that this has been copied to 18 intervenors. If there is anyone else who wants a copy, 19 let us know. 20 Mr. Grieve, I notice that although 21 the letter to the Board, the cover letter on the motion 22 was from Mr. Power, this letter has been addressed to 23 you, so you might want to check your "in" box for it, 24 rather than Mr. Power. 25 MR. GRIEVE: All right. Thank you. 26 MS LEA: Thank you. 27 We are adjourned then until 9:00 a.m. 28 Monday morning at which time we will hear from John 852 Preliminary Matters 1 Todd on behalf of the Vulnerable Energy Consumers 2 Coalition. Nine a.m. Monday, please. 3 Thank you. 4 --- Whereupon the hearing adjourned at 1230, 5 to resume on Monday, September 27, 1999, 6 at 0900 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 853 Preliminary Matters 1 INDEX OF PROCEEDINGS 2 PAGE 3 4 Presentation by OFA Panel 738 5 Questions by Mr. Rodger 749 6 Questions by Mr. White 751 7 Questions by Mr. Grieve 754 8 Questions by Mr. Mia 758 9 Questions by Mr. Cronin 760 10 Presentation by DTE/PROBYN Panel 767 11 Upon recessing at 1034 788 12 Upon resuming at 1053 788 13 Continuation of Presentation by DTE/PROBYN Panel 788 14 Questions by Mr. Rodger 802 15 Questions by Mr. White 805 16 Questions by Mr. Cronin 808 17 Questions by Ms Kwik 819 18 Presentation by Pollution Probe 823 19 Questions by Mr. Grieve 827 20 Questions by Mr. White 829 21 Questions by Ms Kwik 830 22 Questions by Mr. Cronin 834 23 Presentation by ECMI 839 24 Questions by Mr. Cronin 846 25 Questions by Ms Kwik 848 26 Preliminary Matters 850 27 Upon adjourning at 1230 852 28 854 Preliminary Matters 1 EXHIBITS 2 3 NUMBER DESCRIPTION PAGE 4 5 E OFA summary statement 749 6 7 F Summary of Presentation 839 8 of Mr. White 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28