Rep: OEB Doc: 13BFD Rev: 0 ONTARIO ENERGY BOARD Volume: NATURAL GAS FORUM - TECHNICAL CONSULTATIONS ON RATE REGULATIONS, FOCUSING ON PBR - VOLUME 5 4 OCTOBER 2004 BEFORE: R. BETTS PRESIDING MEMBER C. CHAPLIN MEMBER 1 RP-2004-0213 2 IN THE MATTER OF a hearing held on Monday, 4 October 2004, in Toronto, Ontario; Natural Gas Forum - Technical Consultations on Rate Regulations, Focusing on PBR 3 RP-2004-0213 4 4 OCTOBER 2004 5 HEARING HELD AT TORONTO, ONTARIO 6 APPEARANCES 7 GEORGE VEGH Board Counsel BEVERLEY JAFFRAY Board Staff LAURIE KLEIN Board Staff MIKE BERMON ICF Consulting Canada Inc. LEONARD CROOK ICF Consulting Canada Inc. LARRY KAUFMAN Pacific Economics Group CHRIS HAUSMANN Hausmann Consulting DAVE CHARLESON Enbridge Gas Distribution DAVE MATTHEWS Enbridge Gas Distribution TOM LADANYI Enbridge Gas Distribution JIM GRANT Enbridge Gas Distribution FRED HASSAN Enbridge Gas Distribution MARIKA HARE Enbridge Gas Distribution RICHARD CAMPBELL Enbridge Gas Distribution IAN MONDROW Direct Energy GIA DeJULIO TransAlta Energy GREG BADEN Coral Energy PAUL KERR Coral Energy MURRAY ROSS TransCanada Pipelines GORDON POTTER Ontario Energy Savings Corp. CHRISTOPHER GAFFNEY Ontario Energy Savings Corp. MARK ISHERWOOD Union Gas Limited BRUCE HENNING Union Gas Limited STEVE POREDOS Union Gas Limited MIKE PACKER Union Gas Limited TOM ADAMS Energy Probe PATRICK HOEY Canadian Gas Association GERRY HAGGERTY Superior Energy ELISABETH DeMARCO Superior Energy BILL FARQUHAR Northern Cross Energy DARRYL SEAL School Energy Coalition PETER MILNE School Energy Coalition JAY SHEPHERD School Energy Coailtion PETER BUDD Tribute Resources DAVID POCH Green Energy Coalition ROGER HIGGIN Vulnerable Energy Consumers Coalition JOYCE POON Vulnerable Energy Consumers Coalition JACK GIBBONS Pollution Probe PETER SCULLY Federation of Northern Ontario Municipalities JIM McPHERSON TransCanada Gas Transmission East FRANK BRENNAN Aegent Energy Advisors Inc. PETER FOURNIER Industrial Gas Users Association FRANK BASHAM Talisman Energy Inc., Canadian Association of Petroleum Producers GREG STRINGHAM Canadian Association of Petroleum Producers BOB FRASER Canadian Association of Petroleum Producers, EnCana JEFFREY MAYER MxEnergy Inc. ROLAND GEORGE Purvin & Gertz BRYAN GORMLEY Canadian Gas Association JIM GRUENBAUER City of Kitchener DWAYNE QUINN City of Kitchener JULIE GIRVAN Consumers' Council of Canada JASON STACEY Sithe Energy JUDY ALLAN Self-represented CHRIS MACKIE Self-represented 8 TABLE OF CONTENTS 9 PRELIMINARY MATTERS: [15] NATURAL GAS FORUM - TECHNICAL CONSULTATIONS ON RATE REGULATIONS, FOCUSING ON PBR: [40] SUBMISSIONS BY MR. HOEY: [41] SUBMISSIONS BY MS. HARE: [104] SUBMISSIONS BY MR. PACKER: [163] SUBMISSIONS BY MR. ADAMS: [218] DISCUSSION PERIOD: [290] 10 EXHIBITS 11 12 UNDERTAKINGS 13 14 --- Upon commencing at 9:03 a.m. 15 PRELIMINARY MATTERS: 16 MR. BETTS: Good morning, everybody. I'd like to ask everybody to please take their seats. 17 Good morning, once again, and welcome to the Natural Gas Forum as the Board has labelled this consultation process. My name is Bob Betts, I'm a Board Member, and with me today, representing the Board, is Cynthia Chaplin and the two of us have been doing this from the outset. 18 We are sitting today representing the interests of the Board, but not as adjudicators. We are here to guide the process, to oversee the process, to ask questions that other Board Members might like to hear answers to as well, anything that hasn't been covered by the presenters so far. Supporting Cynthia and I in this process are the two key Board Staff people who are Laurie Klein and Beverley Jaffray, and also joining us today are two of the three consultants who have been supporting the Board in producing the discussion papers. Today we have Mike Bermon, who has been with us for the last several days, as well as Larry Kaufman, who has joined us today for the rate regulation part of our process. 19 I'll just give you a little bit of a run down and then I'll introduce -- and doing this I know there are many familiar faces in the group, people who have been here from the outset, so please bear with me for the boredom that this creates, but there's also a few new faces. So I'll just cover a little bit of old territory. 20 First of all, as I said at the beginning, this is not a formal Board proceeding. It is for information gathering and an exchange of views and a debate to inform the Board, to assist in policy development as we go forward. 21 We've given our facilitator the difficult job, and yet he's been doing it very, very well, of keeping us on line and on time. So at times, please forgive him on our behalf for, perhaps, being a little abrupt to make sure the schedule is adhered to. 22 Once again, this is not a formal hearing. We are not expecting there to be cross-examination in the form that we normally see it in a hearing process, but certainly we welcome all parties to challenge the views of other parties. Hopefully, the best way to challenge those is to present a very strong and positive counterview to the points being made by others. 23 If -- I doubt that that has caused any questions. If this has, perhaps I'll ask are there any questions at this point of anybody? 24 MR. PACKER: I don't know if this is the appropriate time, but I have a comment on timing that you had referenced on Thursday. So I'm in your hands. 25 MR. BETTS: This is as good a time as any. Please go ahead. 26 Just to assist us all, because this process is being -- it assists the reporter as well as all the people who are listening on the webcast if each of us introduce ourselves as we take the microphone, and Mr. Hausmann will give you a little more detail about that. So please proceed. 27 MR. PACKER: My name is Mike Packer. I'm with Union Gas. 28 I think it was Thursday when the Board indicated that the timing of submissions had been extended to November 10th, but there was a request that Union try to make the storage competition study completed by EEA available by the 27th of October if at all possible. In that context, EEA will work towards completing that as soon as possible, and hopefully it can be filed by October 27th. 29 I would just note that the storage competition study is fairly technical in nature, and by virtue of its technical aspects, it could be subject to misunderstanding or misinterpretation. As such, if there are comments submitted in the position papers of others, EEA would like to respond to them. We think it only fair to give them that opportunity. In that context, both EEA and Union would request that the Board give EEA a couple of weeks to respond to the submissions of others, if there is a need to do so. We anticipate that that would be fairly short and be clarification in nature. 30 MR. BETTS: We'll consider that and give you a position on that a little later today, Mr. Packer. 31 MR. PACKER: Thank you. 32 MR. BETTS: And it's my pleasure now to introduce Chris Hausmann who is our facilitator. Mr. Hausmann, over to you. 33 MR. HAUSMANN: Again at the risk of boring you, I will just try go through a few mechanics of the proceedings, the way we run them here. The first request would be please make sure all your cell phones are turned off. They do get a little disruptive in the middle of presentations. 34 Secondly, the Chair has already mentioned that these proceedings are being both recorded for transcribing and webcast, so when you do speak, please speak directly into the mike, please identify yourself with your name and who you represent. The first time you speak, if there is a dialogue going on, you don't have to keep repeating your name, but if you come up half an hour later, whatever, please repeat your name so that the people hearing can recognize your voice. 35 Finally, with respect to mikes, please don't turn them up towards the ceiling because we get feedback and that's pretty disruptive. 36 If you make a presentation this morning and there are any revisions from presentations that you submitted to the Board, would you please ensure that a revised copy is submitted to the Board, and if you have it in hand, even preferable if you could provide it to the court reporter so that she can follow along. And in her interest, I would ask that you speak not too quickly, fairly clearly and deliberately so she can get everything down. 37 Finally, we do have a new agenda this morning. Basically, we are adjourning shortly after noon today. One of the presentations dropped off so we're able to put everything into the morning. If you don't have a new agenda, it's pretty straightforward. It's the same as the old one except Energy Probe has been added to the morning presentations, and that means that we get to adjourn at about 12:10, 12:15 today. 38 The way we have carried on these proceedings, we've heard a presentation for about 15 minutes, after that, it's followed by questions of clarification from the Board, and then we move on to the next presentation, and then later on in the discussion section, everybody has an opportunity to engage in the discussion. 39 Any questions? In that case, we will move to the presentations and move to Mr. Patrick Hoey from Anbrer Consulting. Mr. Hoey. 40 NATURAL GAS FORUM - TECHNICAL CONSULTATIONS ON RATE REGULATIONS, FOCUSING ON PBR: 41 SUBMISSIONS BY MR. HOEY: 42 MR. HOEY: Thank you, Mr. Chairman, and other people who are here today. 43 I'd just like to point out that I've been doing some research in interviewing utilities, customer groups, and other stakeholders for a paper that I'm preaching for the Conference Board of Canada, and the views I express today are mine, mine alone, and aren't those of the Conference Board of Canada nor of the Canadian Gas Association. 44 For those who don't know me, I have been in the -- a number of times in this room with regulatory affairs with both Centra and Union Gas, and have had other roles within the companies too as well. So I think I have some expertise in terms of what's gone on in the regulatory field for the last 15 or 16 years as well. 45 The agenda today, I just want to go through what I think are the different stakeholder groups that are involved in the PBR process and try to look at it from what are their expectations, in terms of the conversations I've had with parties in the last little while. 46 Starting with customers, and I mean customers and customer groups, I think the first thing that they really want to do is see some tangible savings that comes out of any PBR agreement. And what I mean by tangible savings is that I don't -- I don't believe that they want to see or be told that this deal will provide rates that are better than what you otherwise would have gotten under some other form. They want to see a dollar amount, they want to see that there is true savings and that they do work themselves into, not only the current agreement, but follow in a review process, if there is some kind of rebasing, that the rebasing also takes that savings into account. 47 Until that happens, I think there's going to be a trust issue here, whether they're actually getting a good deal. If the rates continue to go up but they're going up at somewhat less than they -- what inflation is, they may not consider that a good deal. If there's huge productivity projects going on within the utilities, they are going to assume that there's been huge saving amounts that have gone in there, and, therefore, why should that translate into minimal decreases in rates and/or it could have translated into minimal increases in rates. And, to them, that just doesn't work out to be, I think, a good deal from their perspective. 48 They also want that somehow the process becomes more balanced and transparent. There is a belief, I believe, among customer groups that the utilities hold all the cards, they hold all the information, and it is meted out to them in whatever form or way the utilities wish to mete it out. And, from that perspective, they don't believe that they're seeing the whole picture, and, therefore, again, can't assess whether they've gotten something realistic and real. 49 They also expect that the utilities are going to enter into some kind of comprehensive agreement. They don't want to see an agreement that has a lot of off-ramps, deferral accounts that are non-gas-cost related, because all that means is that, while there's a deal for a little portion of the business, there's still opportunity in other areas of the business for the utilities to earn back what they may have been losing on this part of the deal. 50 This also, though -- I don't think the customers, in talking to them, truly understand that, if it is to become a comprehensive deal, and you are going to eliminate deferral accounts, that you're going to inherently increase the risk to the utility over the time period of the term, and, therefore, there should be consideration for compensation for that, as well. 51 The other stakeholders, and what I mean by "the other stakeholders" here, other stakeholders who aren't necessarily customer groups, such as the NGOs, that are going to be involved in this process, they certainly want to see that their issues are fully addressed. They cannot walk away from a PBR deal that doesn't address anything, or that they are totally ignored. If that happens, they will become a fly in the ointment to the agreement, continuing to process through the term of the agreement. 52 And that's going to be one of the keys that, I think, is -- that the agreement has a length, to stay in place for the entire agreement, and it can't be reopened. But if not all the stakeholders are addressed, then there's going to be a greater pressure that things have been left off the table, and, therefore, something has to be done to open it up and address those issues. 53 Also, sometimes these issues that these stakeholders bring forward are very hard to define. The goals are very ambiguous at times. And, if this is going to be a good agreement, then I think we really have to work -- I think utilities in those parties have to work very, very hard at defining the goals, putting down measurements as to what is going to be called an achievement of the goal, and then be willing to sit there and have it assessed properly. That means, in terms of assessment, you may need a third-party assessor to come in and verify the results of any kind of deal that comes along. 54 When it comes to what the utilities expect, what I've seen and what I've been told is that they expect that the shareholders are going to get an appropriate return for any investment that they've made in productivity. If you go back to a belief that PBR, as a regulatory vehicle, is really to encourage the utilities to improve their productivity, and invest in productivity measures that don't take, usually, one year, but take a number of years, then if that's the case, the shareholders are going to have to ask for an appropriate return on that investment. 55 The two utilities in Ontario are part of large corporations, and they're going to have to fight. If this is capital dollars, they are going to have to fight internally for those dollars coming forward from their corporate parent, and that means that they are going to have to have a certain threshold requirement for rate of return; otherwise, the capital dollars don't move forward. So there's -- so those -- so we have to consider that it isn't just in a vacuum. You have to consider that this is investment of capital dollars for shareholders looking at projects throughout their corporation and throughout North America, in some of the cases. 56 Some of the -- and also, they're looking for a rate of return that's above the allowed rate of return. There's been talk about if 100 basis points is enough. Is it not enough? Is that the proper ceiling? Or, at some point after 100, that we go into a sharing mechanism. 57 If you're going to have a three-year rate -- three-year term on these agreements, you're going to have to have something that's higher than the allowed rate of return; otherwise, why would the utilities want to invest in the productivity measurement? There has to be some financial return for them. And, also, is it just the one-year return? In some of the processes we've looked at, we've had openings, and looks at the agreement, every single year. It may be better to look at a rate of return over the term of the agreement so that, maybe, in the first year, the return is low, and -- but over the -- whether it's a three-year, the three-year is significantly higher than the allowed rate of return, but, on average, may be only slightly above, or at some level that is acceptable. 58 Finally, if the utility was extremely successful, and came up with the ultimate-dream productivity measure that was going to generate significant savings, and earn a rate of return that, I think, would be significantly above any allowed level, either they have to have a sharing mechanism in place or they have to have some way to ensure that there's sharing between themselves and the customer groups. If they don't, it just looks like it has been -- the whole benefit has rolled towards the utility, and the shareholder -- or the ratepayers have not gotten anything out of this deal. There has to be some kind of way of sharing the good fortunes that come along. 59 Because, you know, I think, in terms of doing productivity projects in businesses, and especially in utilities, my experience has been you that don't always get it right, and sometimes you get it really right. And so there's going to be that -- you have to consider that the utilities may not get the best productivity program going the first time. It may take a couple of tries. And then, when it does go really well, though, I think the utilities have to be willing to pony up and give additional benefits that roll to them, beyond what they found acceptable in going into the agreement, back to the ratepayers in some sharing mechanism. 60 Finally, the utilities have expressed, as far as I've seen, a reduction in regulatory expense. And I split this into two different components, what I call both internal and external. External would be the former and today, the lawyers in the room, the hearing time, and all the experts around the table and the filing of it. That is, certainly -- they would like to see that that portion of the process be reduced. But, in addition, utilities have a large internal expense involved in regulatory matters. If you are someone from the marketing department, you may be doing all your work, during a rate-hearing year, almost entirely feeding into the regulatory process. And you won't be doing market research to help them identify the next good program for the utility. 61 If you reduce this regulatory expense, it allows the utility to focus on the productivity programs that they want to move forward with, and try to get the best results that they can possibly get. So that means that we have to, I think, agree as to what the reporting requirements are going to be needed in the interim period, while the term is on, and what is going to be the reporting requirements when the deal is done. When we come back to rebasing, is there going to be rebasing? And what amount of information has to carry forward from the past, from the start of the deal, to the next part of the next deal. And those things should be negotiated right up front so that there is no confusion, no confusion about what are the next steps. 62 Finally, I think the regulator has some expectations, too, as far as I can tell, from what I've read on the OEB website, and other utility jurisdictions. First off, any PBR arrangement cannot change the protection of the customers' interests nor the utilities' ability to continue to be a long-term service provider. And, therefore, this -- these types of agreements have to ensure, at least for the customers, that they are better off. They may have to take more risk, but they must be better off than they were before in their cost of service. 63 There also is an expectation that, somehow, the PBR will be in a more efficient system than the cost-of-service reviews, but this may not happen if the customer review process that may or may not be implemented within the agreement every year, it becomes onerous. It may not occur because of what people want, to reopen the agreements at some point in time throughout the term of the agreement, and if you put any one of those particular things in, you're going to create the risk to both sides of whether the agreement will last and whether they want to reenter one into in the next place. 64 Finally, I think the fundamental reason for using PBR is that somehow we want better long-term performance and innovation coming out of the utilities. The cost-of-service annual review does not lend itself to that type of initiative. It's too short a window to get the returns acceptable for investing in long-term productivity models. 65 However, one also must remember that, as I mentioned earlier, sometimes utilities will try to do certain things under PBR. They may fail, and we must be cognizant that trying, if they made a good try, is one thing, if they didn't try a at all, that is something else I think the regulator must be considering is that the -- are the utilities working in the best interest, long-term best interest for the customers if they are not even trying to move forward with any productivity measures. 66 Finally, one of the key policy issues that I can see is, I've always considered and I think, as far as I can see, a PBR is a contractual arrangement. That means that the parties involved agree that this is what we're going to do and that we'll do it for the entire period. At some point in time during that period, if you don't like what's going on, your time to talk about that is at the end of the term. It's not to try to break it open and crack it open unless there's absolutely serious flaws in it. And that means on any part of the party. And I mean both utilities don't get to reopen it and customers don't get to reopen it. There is a risk to both sides and they have to live with that risk. 67 Also, that means that there's going to be protection for the customers sitting in place, and we were protecting the utilities in their competitive position. Hopefully the agreement is balanced enough that that really doesn't change, but that has to be ensured. And that's I think where the regulator comes in, to ensure that there isn't any -- there is no skewing of the agreement in any particular party's favour. 68 In terms of regulatory risk, that is something that faces the utility, it does not face the customers, and that means that the regulator must be very cautious as how it looks at the agreements, how it accepts the agreements, and whether it will reopen or allow a reopening of the agreements in these contracts. If you start to allow agreements to be opened, reopened, that increases the risk of the utility that won't be reflected in their financial deal that they put forward in the original agreement, and now that would have changed their whole -- what they would have asked for in terms of a return that they would have found acceptable. They're trying to balance off risk with reward, and in changing that regulatory risk equation after the fact, after the agreement is in place, it in effect changes the fundamental financials of the agreement in the first place. 69 Finally, I think there's the recovery of investment on a length of term. This is, I think, a more longer-term policy issue. From everything I've seen so far, if the agreement starts at three years, that's great because there may be opportunities through productivity programs within that time frame. But as utilities become more and more productive, the marginal, the next marginal project that comes along is going to have a smaller return and/or take a longer term to get it back. And that means that we have to start thinking about longer terms, or you may have to think of something even different, of a term something like a three-year, first-year term with a second-year term attached to it where only half the savings kick in after the first three-year period, and the remaining of the savings kick in at the end of the six year period. 70 So that once you get this process up and running, it could be continuous that the customers are getting huge savings every third year on thier bills. It's just that the investment has a six-year window in which to recover its costs rather than an initial three-year period. And I think those will be the key things once -- if this process gets into place for a serious period of time. And that's my comments. 71 MR. HAUSMANN: Thank you, Mr. Hoey. Perhaps, while we're hearing questions from the Board, we could cue up the Enbridge presentation. Questions from the Board? 72 MS. CHAPLIN: Cynthia Chaplin. Mr. Hoey, could you, perhaps for my benefit, could you just go over again I think it was in relation to the last point you were making about, sort of, an alternative structure. You were talking about a three-year term or I take it maybe two three-year terms but linked. I didn't -- 73 MR. HOEY: Instead of having, let's say, a six-year term project, you could have a three-year term project that's linked. In the initial agreement, what you would say is, Let's run a three-year term. We determine what our savings are but we know that this productivity measure needs a longer-term period, from the utility's perspective, to put a return back that's appropriate. So instead of giving -- for argument's sake, let's say there's $30 million worth of savings, instead of giving them $30 million worth of savings it hits the customer at the end of the three-year term. Fifteen million hits them at the end of the three-year term and at the end of the six-year, the second piece, they would get the whole 30. But then you would probably start another productivity measure at the start of that fourth year, in that there may be additional savings that go on top of the 30 at the end of six. So it's kind of a rolling piece that moves along -- that keeps adding on. 74 MS. CHAPLIN: So the PBR term itself would be three years, but you're describing a mechanism that would recognize particular programs that might straddle several terms. 75 MR. HOEY: That's right. 76 MS. CHAPLIN: Thank you. 77 And when you were speaking about the utility perspective and explaining the expectation of being allowed to earn a return above the allowed return, was I correct in your recommendation that there be some fairly large band within which there would not be sharing? Did I take your point ... 78 MR. HOEY: No, I wasn't suggesting that there be any band, but the way I would phrase it, if there was a band, whether it's 100 basis points -- 100 basis points seems to be the number that everyone plays with -- but what I was suggesting was that if the utility, for argument's sake, didn't have a sharing mechanism in place and for some reason and they put in the program, there was 100 basis points program that they could earn up to. And for some reason, everything went absolutely perfect and they earned 250 basis points, my suggestion would be before you even get back into the hearing room, I would be starting to think about giving some of that return back to shareholders. 79 You've had a windfall gain, and maybe that you give back 50, you may give back 75, whatever sharing mechanism, but go talk to the customer groups and talk to them about -- we were extremely pleased with our program. It went beyond our expectations. Our expectations were that it was going to earn X return, it earned Y. We feel, as part of the agreement -- it wasn't in the agreement, but we feel that you should get back some additional savings as a result of this. It will also come through in rate basing, but in terms of return as well. 80 So that there has -- what I'm getting at is a level of trust. Otherwise, if that goes on, all the customers believe is that, Well, that worked great and the next time they are going to do it again and we're still not going to get the full benefit of what they're doing. They said that the program was going to work at X level, they knew all along it was going to work at Y. So dispelling that and creating a trust level between the two parties. 81 MS. CHAPLIN: So are you suggesting that, sort of in the normal course, you wouldn't -- I guess -- in the normal course, would you try to negotiate what that point would be beforehand? Or are you suggesting that we -- 82 MR. HOEY: I would suggest that utilities could negotiate. If they understand what their productivity program is, they should have some estimate of what their savings should be, and you should be able to negotiate the savings up front. If for some reason the program went way better than expected, then why don't you share the wealth with the customer group instead of -- for argument's sake, you negotiated that the savings in the program were going to be $30 million and for some reason it turned out to be 50. Shareholders, yeah, they could get rewarded, but so could ratepayers. They shouldn't just maybe get the 30 million, they should get some additional portion of that additional over 20 million. And that's what I'm suggesting here, is you're trying to create a greater trust factor. 83 That's one thing I did pick up in the discussions with the different groups, that there is a lack of trust that there will be a sharing of the savings back to the customers. And I think it's imperative upon the utilities to start thinking of how they can create that trust back into the game; otherwise, there will be no PBR agreements. 84 MS. CHAPLIN: And the conversations that you had, were they primarily with the stakeholders within the Ontario arena? 85 MR. HOEY: Yes. But I've also talked to other provinces, as well. 86 MS. CHAPLIN: And, from your discussions with the various stakeholder groups in Ontario, was it your conclusion that there is an appetite to pursue this or not? 87 MR. HOEY: From the customer group side? 88 MS. CHAPLIN: From whatever. 89 MR. HOEY: I think -- from all sides, I think there's a lot of hesitancy on all parties to pursue future PBR agreements. The first ones, I just don't think they went well, and I think it goes back to, there's a lack of trust. There's a lack of -- and I mean on both sides, that they want to crack the agreement open if things aren't going right, or things are going too well, that we don't know what the numbers are. I think it is more imperative upon the utilities to come forward than the other groups, because it will be the utilities who are asking to have a PBR mechanism, and it's up to them to make it work. And they're the ones that have to really improve the trust factor with the other parties. 90 At the same time, I think the customer groups have to realize that, if this is to move forward, the utilities must earn a return greater than where it was before, and there may have to be some dealing between costs and prices. It is, Well, if you're satisfied with the price, then what's wrong? I use the analogy, if you go into a car dealership and you get -- you negotiate and you get a good deal, you never know the cost, sometimes, as long as you're happy. But if you found out what the cost was after the fact, you'd go, Oh, I got a bad deal, all of a sudden. It's that kind of process of, I think I got a bad deal because I gave them too much profit. But a day earlier you were happy because you thought you'd gotten a good part of the deal, too. 91 So I think there may need to be a dealing between the cost structures of the utilities, and focus more on, Okay, what do you want, as customers, as rate results? Do you want flat rates for the next five years for the distribution part of the utility, or do you want a declining rate? What do you ultimately want in terms of price, what you're going to be charged? Forget about what it's going to cost the utility; let them figure out whether they can offer that. 92 MS. CHAPLIN: Thank you very much. 93 MR. BETTS: Thank you. 94 First of all, I wanted to say thanks for your opening with that expectation of parties. I think it was a good way to start this discussion off. And, certainly, I think you covered all that I could think of, but maybe we'll hear from others that can come up with other expectations they have. 95 One of the items that you mentioned was regulatory risk, and you used as an example in that case, the risk of the agreement being opened up part way through, prior to the termination of the agreement. Are there any other forms of regulatory risk that come to your mind, that the regulator could control? 96 MR. HOEY: It could be a dissolution of deferral accounts, how deferral accounts are treated within the agreement, or ex parte of the agreement. But I think the big one would be whether the contract could be opened or not opened. And also, the other regulatory risk that could sit there -- and it refers to what I'll call that, that -- Cynthia was asking about the three-year-plus-three-year agreement. If there is some carry-over from the first term to the next term, if you don't get the same panel looking at it, somehow there has to be an acceptance that that transfer's going to move in the way it was expected when it was first struck, that first day. If that transfer of dollars doesn't, to the next level, to the next term, and there's another panel sitting there, that changes the whole financial formula that was figured out at the front end of the agreement. So it's -- that would be a regulatory risk in terms of it, as well. If you came in for a rebasing, or whatever, and somehow that changed the whole look of the agreement from where it was three years prior, I'm not saying you shouldn't do it, I'm just saying that is a risk that is going to change the whole financial analysis that was struck at the original part. 97 MR. BETTS: Can you maybe comment for me on this: Most regulators, and certainly the Ontario Energy Board is not an exception, expect a certain amount of reporting and record-keeping during any agreement, and, I think, a longer-term PBR would probably be an example of that. Can you comment how the utility reacts to that. I think, in many ways, I sense that it's almost an intrusion, and it may, in fact, create some anxiety. Do you care to comment on the issue of reporting requirements? 98 MR. HOEY: In thinking about this, I think part of the agreement in process should also clearly talk about what reporting requirements are going to be required, if it's annual at the end of the term; what papers, what forms, what do we want to compare to? Agree to that all up front, and rather than it being, Oh, can we have -- and I'm not specifically talking about the regulatory board but also all other intervenors -- Oh, well can we have that piece, too? And can we have this piece too? And the reason I say that is my experience from the utility perspective is that, going back and finding out information after the fact when you haven't had it -- when you could have created it as you were going by that time period versus going back and having to rehash it, increases the workload tremendously for the utility and for anybody. 99 If I asked OEB for the records of four years ago, now, on a particular piece of information, it would take a lot of work. Had I told you five years ago that I would be wanting that one year out, you would have created that just as you were going by. 100 So I think part of the agreement there should also be clear thought about it, what information do we really need from the different parties, and can we agree on that up front as well. I think that'll smooth the whole process out to a certain extent, and meet everyone's expectations, hopefully. 101 MR. BETTS: Thank you. Those are all our questions. 102 MR. HAUSMANN: Thank you, Mr. Chair. 103 Are we ready -- is Enbridge ready to proceed? 104 SUBMISSIONS BY MS. HARE: 105 MS. HARE: Yes, thank you. 106 Good morning, my name is Marika Hare and I'm director of regulatory affairs, Enbridge Gas Distribution. And we certainly appreciate the opportunity to be here today and discuss our perspectives on rate regulations in Ontario. 107 I'm going to follow the same approach that the Enbridge panels did last week, which is that I will be providing an overview of the comments that we made in greater detail on September 20th. I'll also not attempt to address any of the comments from other stakeholders in their written submissions. To the extent that we feel that's required, we'll do that in the submission on November 10th. 108 I'd like to make six general points this morning. 109 First, we encourage the Ontario Energy Board to provide guidance to utilities and stakeholders on the forms of incentive regulation for gas utilities that the Board would find acceptable. Five years ago, PBR was an experiment. Today, the Board has had experience with the electric distribution utilities operating under PBR plans. They've had the experience of Union Gas's comprehensive PBR plan, and Enbridge Gas Distribution's targeted PBR plan, which covered operation and maintenance expenses, only. 110 So this experience, taken together with the experience in other jurisdictions, which the consultant's report outlines, we believe, does provide sufficient information for the Board to provide direction. And we request that the Board's policy paper on rate regulation, which we would expect to be a step in this process, would provide a clear indication of the Board's objectives and expectations with respect to PBR, as well as draft guidelines on the parameters of incentive regulation. 111 Patrick spoke about the expectations of customers and the expectations of the utilities. What we very much need would be a statement of what the Board's expectations are. And, when I speak about the parameters of PBR, these would be the basis for the separate applications by the natural gas utilities at some future point and we have provided some views of what those parameters should be. 112 The second point I'd like to address is that in making a rate application, LDCs should be able to choose between cost-of-service regulation or the alternatives made available by following the Board's incentive regulation guidelines. 113 Now, that may seem a bit unusual because Enbridge has long been an advocate of multi-year plans and what we're suggesting, though, is that the utility should have the choice as to whether they choose to pursue a long-term incentive regulation plan or standard cost-of-service. Because we feel there might be occasions when cost-of-service is considered preferable by the utility. That would be, for instance, where there's cost incurred due to technological change, maybe economic swings or new regulatory requirements. 114 Now, I'm not suggesting that once under an incentive regulation plan, so if, for example, the contract as Patrick described it is a five-year plan, that the utility would be able to then say no, we're under cost-of-service, but between plans, the utility should have the right to choose. 115 The third point is that Enbridge believes that the efficiency of the cost-of-service rate regulation process can be improved. Improvements may come by standardizing a filing requirement, refinement of issues lists, coordination of interrogatories, or perhaps by consideration of two-year or maybe longer cost-of-service plans. And we will be making specific suggestions in this regard in our further written submissions. 116 Fourth, it's apparent to us that pure forms of performance-based regulation of the type first used by telcos, which would be revenue or price cap based on inflation less the productivity challenge, is not supported by stakeholders in the energy sector in Ontario. Board member Paul Vlahos made similar comments at the CANPUT presentation this past spring, where he observed that the utilities aren't willing do pursue PBR plans that don't have deferral or variance accounts. So in his view, none of the stakeholders were willing to go forward with what would be a pure PBR plan. 117 So utilities' concerns about risks beyond management's control lead to a desire for Z-factors, deferral of variance accounts, and regulators or consumer representatives that worry about the potential for excessive utility income require that an earnings sharing be included. 118 So recognizing this, Enbridge has been using the term "incentive regulation" to refer to forms of regulation other than an annual cost-of-service application. We believe that a multi-year formulaic approach to rate-making can be constructed that has sufficient incentive for utilities, while ensuring that the gains captured are appropriately shared with ratepayers. 119 Fifth, Enbridge Gas Distribution wants to understand the flexibility available to it to pursue alternative business and legal structures while within an incentive regulation plan. Parties familiar with Enbridge's targeted PBR plan, which was in place for the years 2000, 2001, and 2002, will recall that stakeholders raised issues about company outsourcing within the plan. And this led to motions to the Board to reopen the plan, and after the plan conclusion, we returned to an extensive cost-of-service review for 2003. 120 Looking back, it's clear that the utility had different expectations than stakeholders about issues such as disclosure and the ability to outsource during the plan. And the point is, that next time it's important that all parties understand the rules and expectations in advance. 121 Looking forward, the company suggests that efficiency improvement would be unnecessarily limited if we only focus on operating efficiencies and O&M and plant investment. And as the discussion paper points out, our company faces the cost pressures of a robust customer growth, combined system integrity investments, and declining average consumption per customer. In addition, our benchmarking evidence, which he have filed in recent rate cases indicates that we're already considered to be of superlative performance relative to other large natural gas utilities in North America. 122 So the company notes that trends towards consolidation and the use of alternative capital structures in the energy distribution sector in North America. The restructuring of the electricity distribution business, for example, in Ontario, from over 300 LDCs to just under 100 is an example of what's happening in this province. So while the company will certainly pursue operational efficiencies under either cost-of-service or an incentive-based plan, Enbridge Gas Distribution requests that the Board provide guidance on the flexibility available to management to pursue merger and acquisition opportunities, alternative business and legal structures, and outsourcing arrangements within an incentive regulation plan period. 123 Finally, this slide lists some of the attributes which, from a company perspective, are desirable in an incentive regulation plan, and I want to highlight a few. 124 First, we support the concept of earnings sharing. While there are many forms of earnings sharing that could be considered, the company supports an earnings sharing mechanism which is referenced on an annually-determined Board-approved rate of return on equity and an appropriate dead band. 125 Considerations about symmetry would depend on whether the earnings to be shared are based on an actual normalized basis. Second, the plan should be simple, transparent, and predictable. We could all spend a lot of time and money considering statistical research and technical debates about appropriate price indices, potential input price differentials, total productivity factors and stretch factors, but we don't think that's necessary. In fact, we think it's counterproductive. 126 We propose that Ontario's CPI be used for escalation purposes in the next incentive plan. There is precedence for its use and it's an index that's understood by customers. By applying a discount factor against the forecast of inflation, a productivity challenge or consumer dividend can be provided. The result is a plan escalation factor that's easily understood. Risks that the index does not approximate the utilities' specific inflation experience are then mitigated with an earnings sharing mechanism. 127 Enbridge believes that a PBR cost-of-service and then return to PBR cycle is not a desirable change to the regulatory model. PBR should be a new regulatory paradigm that's sustainable. 128 At the end of a PBR plan, Enbridge Gas Distribution proposes that the parameters of the next generation PBR plan could be negotiated with stakeholders and determined by the Board without cost-of-service rebasing. The filing of information throughout the plan in consideration of external benchmarks should satisfy stakeholders and the Board that the rate changes within the incentive regulation plan are just and reasonable. 129 There are examples of plans that have been renegotiated without returning to cost-of-service rebasing. These include Enbridge's incentive tolling agreement for its liquids pipeline and Gaz Met's current PBR plan. 130 That concludes our overview. Whether it's cost-of-service regulation or incentive regulation, the bottom line is that we're looking forward to rate-setting processes that are lighter handed, take advantage of formulaic approaches, are multi-year, take less than 10 months to get approved, and are fair to both customers and our shareholders. Thank you very much. 131 MR. HAUSMANN: Thank you, Ms. Hare. Perhaps we could set up the Union presentation while we hear the questions from the Board. 132 MS. CHAPLIN: Thank you, Cynthia Chaplin. 133 Ms. Hare, you commented towards the end there that a PBR cost-of-service -- PBR cycle wasn't desirable, sort of having cost-of-service rebasing. I took it to mean that having cost-of-service rebasing in between two PBR plans would not be your preferred approach. 134 MS. HARE: That's right. 135 MS. CHAPLIN: You talked about how the LDCs should retain the discretion to choose between cost-of-service and incentive-based. Those don't immediately seem consistent to me. Perhaps you can elaborate or explain where I might have got it wrong. 136 MS. HARE: In the first instance where we talked about the utility choosing, it would be at the end of a plan period when the utility determines, for a number of reasons, that it would prefer weighing the risks and potential rewards to stay in the cost of service for either one year or two years. But that would be the utility's choice in how it applies for rates. 137 In the second instance, it would be the expectation that, in between plan periods, there must be rebasing. And, in rebasing, whatever efficiencies are gained are then given back to the ratepayers. And that's the model that we don't think is sustainable in the long run. It's the expectation that at the end of a plan period, there's rebasing. So, in other words, there's agreement that the company would stay on an incentive regulation plan, but in between those two periods, there would be a return to cost of service. 138 MS. CHAPLIN: But am I correct in understanding that if something had happened to your cost structure, and you wanted to be rebased, you would want to retain the discretion to do that? 139 MS. HARE: Yes. 140 MS. CHAPLIN: So you want to be able to rebase if costs have increased quite significantly, but if you achieve the significant savings -- so in other words, it's not symmetrical. I'm correct in ... 141 MS. HARE: It would be going back to a discussion of risk and reward. If, in the forecast of the next year, the utility believes that there are unknown risks, then it would be hesitant to go into a five-year plan again. I mean, the beauty of cost of service is that, if you get it wrong in any particular year, you have the ability to go back the next year and get it right. But, in a five-year plan, if you get it wrong, the company could be at risk. 142 Similarly, without earnings sharing, the ratepayers may be giving up more than they need to, and this is why we think earnings sharing is important. But what we're talking about is the situation where the utility is uncertain whether, because of changes in the environment, it wants to go into a five-year plan. 143 MS. CHAPLIN: And you've suggested that it would be helpful if the Board published guidelines setting out, even to the extent of setting out parameters. 144 MS. HARE: Yes. 145 MS. CHAPLIN: Would that include identifying up front what an appropriate earnings sharing mechanism would be, and what an appropriate dead band would be? 146 MS. HARE: It could, but we actually see that the incentive regulation plan -- there is a list of parameters, and the best plan is probably one that looks at the combination of parameters. So to say that a dead band should be 100 basis points in and of itself, we don't believe makes sense. The dead band, we think, would be established giving weight to what the productivity factor would be. 147 So, if, for example, a productivity factor is particularly onerous, then the dead band should be broader than if there's agreement that the productivity factor is not a huge stretch factor. So these things have to be designed in combination. 148 What we're hoping for in using the CPI example, though, is to avoid the debate within an individual company plan as to whether or not it's industry-specific, or whether it's GDPPI, or whether it's an inflation based on CPI. Those are the kinds of general parameters that we think Board guidance would be helpful, as opposed to spending the time in individual cases. 149 MS. CHAPLIN: Thank you. 150 MR. BETTS: Thank you. Ms. Hare, just a couple of questions from myself. It's Bob Betts here. 151 First of all, can you foresee a circumstance, in your mind, with an appropriate PBR plan, where we could, in fact, expect to have no deferral or variance accounts? And, if the answer to that is no, which ones? I don't mean specifically, but what type of deferral and variance account do you think is unavoidable? 152 MS. HARE: Well, the easy answer is the purchased gas variance account which, with the volatility of commodity prices, would definitely have to be retained. But there are other deferral and variance accounts that, I think, the company would want to keep in place. And again, these would be situations where the amount in the deferral account can't be predicted. And that's why it would be to the advantage of ratepayers, or the shareholder, to retain it as a deferral account, where the amount is really not able to be predicted with any certainty. 153 MR. BETTS: Would that be a general qualification, in your mind, that a deferral or variance account must be one where the outcome could shift either one way or the other, to the utility or to the customer? Or could you foresee them being set up so that they would only benefit one party, depending on the variations? 154 MS. HARE: No, I think, by definition, the deferral accounts and variance accounts could go either way. I'll give you another example. A few years ago, we negotiated with the intervenors to have a deferral account for unaccounted-for gas. The shifts in some years were $16 million, and they have gone both to the shareholders' benefit and to the ratepayers' benefit. It's a situation that can't be controlled by management. But the dollars are significant and, again, could go either way. 155 MR. BETTS: Thank you. And the other point with reference to the Board publishing guidelines. Let's assume that that was possible, let's assume it happened, and let's assume it happened after an appropriate consultation process. Would you expect that the Board -- would you expect that the utilities would thereafter submit all of their applications in that form? Or could you see the utilities reserving the right to submit an application in whatever form they chose? 156 MS. HARE: I would think that the guidelines would have some flexibility. In my mind, what I would envision would be some broad principles set out. For example, my assumption is that one of the objectives of having PBR for the electric utilities was for administrative simplicity. That same objective probably doesn't apply to the gas utilities that have a long history of information on the record, which the electric utilities didn't have. And so, to try to regulate, for the first time, a hundred electric utilities, was a different burden than for the gas utilities. And so there is a difference in objectives, I think, of the Board for gas utility PBR or incentive regulation and electricity. 157 Patrick talked about regulatory oversight, and some of the others -- although I said I wasn't going to comment about some of the other papers, some of them do talk about whether or not reducing the regulatory burden really is an objective of incentive regulation. From the utilities' perspective, it is. It would be very helpful to know if that's shared by the Ontario Energy Board. So that's what I mean by an example of guidelines. 158 Similarly, without getting into the details of outsourcing, and there have been a number of papers that Enbridge representatives have delivered about what happened with outsourcing in targeted PBR, let's take the example of financial restructuring in the case of either a merger or an acquisition, or just capital refinancing of the utility. 159 We don't want to get into a five-year plan and pursue something in year 2, only to find out that the Board, in principle, is opposed to the utility doing this. So we'd like to have those broad principles set out and objectives in the guidelines. And we'd assume that there would still be flexibility, then, for the utility to make an application, but in accordance with that framework. 160 MR. BETTS: Thank you. No further questions. Thank you very much. 161 MR. HAUSMANN: Thank you, Mr. Chair. 162 That takes us to Union Gas. Mr. Packer, will you make your presentation, please. 163 SUBMISSIONS BY MR. PACKER: 164 MR. PACKER: Good morning. My name is Mike Packer. I am the director of regulatory affairs for Union Gas. We appreciate the opportunity this morning to provide our comments on rate regulation in Ontario. The PowerPoint presentation that we provided to Board Staff in advance is a little lengthy, and it's not something that I could get through in its entirety in fifteen minutes. So this morning I'll just hit on the highlights. 165 I wanted to start with a summary of Union's position. In our view, our first-generation PBR plan was not a success. We believe the Board needs to make some decisions about what outcomes it's looking for so that the appropriate regulatory framework can be put in place to deliver on those outcomes. 166 Based on feedback we received from stakeholders, there appears to be support for a retention of some form of cost-of-service regulation, and this may, in part, be related to challenges that exist in setting appropriate PBR price-cap parameters. 167 We believe cost of service could be modified to improve regulatory efficiency, and still result in just and reasonable rates. And, in that context, we're suggesting the Board consider a modified cost-of-service framework with incentives, where cost-of-service proceedings would happen every few years, for example, five years, and rates would be set by applying a factor of CPI against the existing rate between cost-of-service filings. 168 In order to protect ratepayers and the utility from wide fluctuations in earnings, we're suggesting that an earnings-sharing mechanism could be introduced, where earnings above and below the allowed rate of return are shared on a 50/50 basis. 169 I just wanted to summarize the type of regulation Union Gas has been under in the most recent history. For all but three years, we've been under cost-of-service regulation. For the period 2001 to 2003, we are under a trial PBR price cap regime where prices were set in relation to that price cap mechanism. I would note that during 2003, we attempted to negotiate a multi-year settlement with stakeholders. Our efforts were largely unsuccessful, and stakeholders expressed a desire to return to cost-of-service following the trial PBR plan. 170 I'm not going to dwell on the parameters at this point. I would move forward to page 9 for anybody's who's following along in the PowerPoint presentation. 171 The ICF report identifies a number of attributes that must be present for PBR to be successful, and we agree with the ones that are identified in the presentation. The first one being that there is a long-term commitment accepted by all participants in the rate-making process, the utility, customers, intervenors, and the Board. 172 We believe that objectives of the plan should be set out in advance and as the plan unfolds, it would be evaluated relative to those pre-set objectives. PBR can provide incentive to the utility to achieve productivity improvements and provide customers with stable and predictable rates. On the other hand, cost-of-service can provide rates that reflect costs and provides intervenors and others with an opportunity to understand in detail the utility's cost, revenue, and through-put structure. 173 In addition, the ICF report identifies that there are a number of "musts" in terms of stakeholders. Stakeholders must be able to identify benefits, must be able to accept that there's less of a relationship between price and cost under PBR than what exists under cost-of-service regulation, must acknowledge that there is greater utility business risk with PBR which needs to be matched with an opportunity to earn higher returns, and stakeholders must have well-defined information filings. 174 Lastly, the ICF paper references that the planned parameters, PBR price cap planned parameters, such as productivity and input price should be set using objective and verifiable industry data. In our view, these studies are best conducted under the auspices of the Board. 175 I just want to make a few comments with respect to how our trial PBR plan stacked up against these attributes. In terms of a long-term commitment, we were required to rebase upon plan expiry. In terms of objectives of the plan, we had identified a number of objectives that supported the plan we had proposed to the Board. Those objectives were referenced in the Board's decision, but it wasn't clear to us exactly what objectives the Board's plan was set out to achieve. We were required to provide revenue-to-cost ratios throughout the term of the PBR plan. The S&T deferral accounts that existed under cost-of-service were continued with a different sharing mechanism than existed for other earnings. 176 In terms of benefits, I just note that two of the three years of the plan had rate reductions for consumers, and in the third year of the plan we did actually exceed the earnings sharing dead band and we will be sharing earnings with customers at a future point in time. 177 In terms of the plan parameters, because industry data did not exist, we commissioned a study of our own productivity and input price experience that we filed as part of our plan. Because it was a company-specific study, parties took us to task on whether it was an appropriate way of setting our parameters. I think in large measure the Board relied on productivity factors that had been approved in other jurisdictions when they approved the productivity factor that should apply to us in that three-year period. In the end we had a two and a half percent productivity factor placed on us which included a 1.1 percent input price differential. 178 The PowerPoint presentation references a number of criticisms that we've heard from others, a number of areas where people are dissatisfied with our plan, some of which we've expressed ourselves. I'm not planning to go through those in any detail at this point, but for who would like to leaf through them they are on page 11 and 12 of our PowerPoint presentation. 179 I wanted to make a comment on a couple of assertions that appear in the ICF paper, primarily that there's little evidence that North American regulators fail to properly evaluate technical evidence and the TFP trends approved by regulators in various jurisdictions are within a relatively narrow range. It's been our experience that experts can differ on how to complete TFP studies and that a TFP and an input price study is very complex, and as you see we've listed half a dozen or more areas where experts can disagree. And our experience with our trial PBR plan is that in our case, there were disagreements around most of these major components. 180 The second item is the notion that the TFP experience in other jurisdictions could apply to Union Gas or other utilities within the province of Ontario. In preparation for today's discussion, I looked at a TFP study that had been filed in the Boston Gas case where the productivity experience of a number of U.S. LDCs in the Northeast were identified. If you look at number of customers as the output measure, our productivity experience is very similar to that experienced by U.S. LDCs in the Northeast. However, if you look at a combination of volume and number of customers, or just volume, our TFP experience is much different, and that's important because a large portion of our revenue stream is recovered through on volumetric charges. 181 It's really a function of the experience in Ontario reflecting declining use per customer, where it's actually the reverse in the U.S. Northeast, the volume per customer is increasing. 182 I just caution the Board about adopting standards or TFP output from other jurisdictions without recognizing differences that exist between ourselves and LDCs in other jurisdictions. 183 Page 16 now. We tried to identify what we think whatever regulatory framework the Board approves should contain. It should be fair to both the utility and to ratepayers. It should be simple and easy for everyone to understand. It should be comprehensive, in that it should include O&M and capital. It should result in stable and predictable rates for consumers with no retroactive adjustments. It should be sustainable in terms of standing the test of time and not being in need of major tweaking. It should be efficient, should align stakeholder interests, should be conducive of capital investment and should be understood by consumers. 184 In our view, the regulator and stakeholders do not appear to accept the permanent move to PBR, and the annual cost-of-service proceedings are far too resource intensive, inefficient and costly. Therefore, we attempted to craft a proposal that would be easy for everyone to understand to try to achieve some of the benefits of both cost-of-service and PBR. 185 In this context, we're proposing a modified cost-of-service framework with incentives, where the Board could maintain a periodic, but not annual, cost-of-service regime. We're providing an example of a cost-of-service proceeding every five years, and rates would be adjusted between cost-of-service filings by a factor of CPI. 186 In order to protect both the ratepayers and the utility from wide fluctuations in earnings, we're suggesting that the Board could implement an earnings sharing mechanism with no dead band and a 50/50 sharing of actual earnings above and below the targeted rate of return. We would suggest that earnings sharing amounts due to consumers be accumulated and disposed of at the time of cost-of-service hearing, and, in that context, it would allow for some offsets of charges and credits to occur and it would deliver fairly stable rates to consumers. 187 We don't believe multiple sharing bands are necessary and we don't believe if you don't have an earnings sharing mechanism that you need an explicit productivity stretch factor. 188 The Board's draft rule on reporting and record keeping could identify what information filing requirements there are. The Board could consider annual or semi-annual meetings with customers to discuss non-rate-related issues. And in this context, upstream commodity transportation prices could still be set using the QRAM process or whatever process replaces the QRAM that comes out of this Natural Gas Forum setting. 189 In that context, there would still be a need for annual prudence reviews so that we can get some comfort that our deferral account balances related to gas costs are recoverable from consumers, both credits and debits. 190 In conclusion, Union doesn't believe its first-generation plan was a success. We're calling on the Board to identify what outcomes they would like and then the appropriate regulatory framework can be put in place to achieve those outcomes. Based on the stakeholder feedback, we received -- there seems to be support for a retention of some form of cost-of-service regulation. This may, in part, be related to the challenges that exist in setting appropriate PBR price-cap parameters. We believe cost of service can be modified to approve regulatory efficiency and still result in just and reasonable rates. In that context, the Board may want to consider a modified cost-of-service framework with incentives. Thanks. 191 MR. HAUSMANN: Thanks, Mr. Packer. 192 Mr. Adams, could you maybe cue up your presentation while we hear questions from the Board. 193 MS. CHAPLIN: Thanks, Cynthia Chaplin. 194 Mr. Packer, the modified cost-of-service framework that you've described, how would you see that impacting on incentives for the utility to implement productivity improvements? How would -- how do you contrast the incentives under the structure you're proposing versus, perhaps, a traditional PBR structure? 195 MR. PACKER: What we're trying to do in the modified cost-of-service structure is reflect the feedback that we've received, that most people, most stakeholders, are still desiring an ability to look at our detailed costs and revenue structures. So, if you take that as a given, what we're trying to do is to create some incentives between cost-of-service proceedings, drive out efficiency gains, and, by having less frequent cost-of-service proceedings which do absorb a lot of resources and are time-consuming, that would free up resources to look at other things, such as productivity-enhancement initiatives. 196 MS. CHAPLIN: And you're suggesting that, basically, you don't need a stretch factor because the earnings-sharing mechanism will create some incentive; is that correct? 197 MR. PACKER: That's right. 198 MS. CHAPLIN: And is Union's position that, under a PBR framework, if that were to be the way things unfolded, that that should take place without a rebasing exercise? 199 MR. PACKER: Sorry, if the -- the question is, if we -- 200 MS. CHAPLIN: Well, at the end of one PBR term, shall we say, how do you get to the next PBR term? 201 MR. PACKER: Sorry, in the context of our suggested -- 202 MS. CHAPLIN: No, I'm sorry, in context of -- let's say the Board were to attempt to pursue PBR, and things were to progress that way. Is it your position that, in a PBR framework, a PBR plan -- what happens at the end of one PBR plan before the beginning of the next? Is there a rebasing and a cost-of-service-type examination of costs, or not? 203 MR. PACKER: In our view, when you choose PBR as your rate-making structure, you do so on a more permanent basis. It's not something that you can flip-flop back and forth between cost of service and PBR. 204 We've had some experience with that, and it wasn't overly pleasant. Reference the comment that Patrick made about understanding what information you're going to need to produce in a particular hearing. Our experience in rebasing in 2004 was that parties wanted us to go back and be able to show a lot of detail, back to 1999, and explain variances, and so forth. That wasn't something we were anticipating doing. It wasn't something we were staffed to do, and it was a very painful process. And I think it generated a lot of suspicion on behalf of intervenors that we were hiding information. In reality, it was information that really wasn't available, nor tracked. It was a type of information that is provided in a cost-of-service proceeding which you don't necessarily focus on when you're operating under PBR. 205 It's very difficult to move back and forth between the two regulatory regimes. We suggest the Board, if they're considering PBR, that they do so with the understanding it's more of a permanent rate-making structure as opposed to something you alternate back and forth between. 206 MS. CHAPLIN: And by that, do you mean a more streamlined review in between plan periods? 207 MR. PACKER: In support of our first-generation PBR plan, we suggested that there not be an automatic rebasing mechanism; that if parties are generally comfortable with how PBR worked, there be an option to extend it. And I guess that's our -- that's still our position in terms of, if the plan is working reasonably well for everybody in terms of is it delivering them the objectives that we've suggested the Board might want to consider, then why do you need to go back and rebase and deal with all the detail that typically accompanies a cost-of-service proceeding. 208 MS. CHAPLIN: Okay. Thank you very much. 209 MR. BETTS: These are probably questions that follow Ms. Chaplin's. It's Bob Betts here. I think I want to try and understand clearly the difference between your modified cost-of-service approach versus PBR with rebasing at the -- when you're coming out of the PBR period. How do those differ? 210 MR. PACKER: I guess, from my perspective, the difference is everyone understands that the utilities are under a cost-of-service form of regulation, and hopefully, in advance of embarking on this type of structure, there's a clear indication of what types of information we'll be called upon to provide in that cost-of-service proceeding. Those types of things would be different than what our experience was the first time around. 211 The difficulty we have with embarking on PBR again is, the Board's decision that approved our trial PBR plan provided us with direction that we should come back with industry studies for storage, transmission and distribution, with productivity and input price. Those studies don't exist. It's our opinion that there aren't necessarily a lot of people interested in participating in such a study. We think it should be broader than Ontario, with just two large LDCs, and, when you start extending it outside of Ontario, there really isn't a lot of interest to participate. 212 Put that together with the complexities that we've experienced and we just don't think PBR is a workable solution in our particular case. 213 MR. BETTS: You referred to the need, I think it was within the structure of your modified cost-of-service proposal, for annual prudency reviews, and I think you used, as an example, reviews to clear variance and deferral accounts; am I correct, first of all? 214 MR. PACKER: Yes. Under our suggested modified cost-of-service framework with incentives, I don't believe there would be a need for a lot of non-gas-supply-related deferral accounts. The comment about prudence review was with respect to gas supply issues and costs that we incur to supply gas, and making sure that there's a prudence review with some regularity so it doesn't get accumulated for five years and then we face having to defend something we did in the gas-supply arena five years before, with the benefit of hindsight. 215 MR. BETTS: Thank you. No more questions. 216 MR. HAUSMANN: Thank you Mr. Chair. 217 Mr. Adams? 218 SUBMISSIONS BY MR. ADAMS: 219 MR. ADAMS: Just before I get rolling, I wonder if I could just seek some guidance from the Board. My presentation was originally scheduled to end at 10:30. Do you want me to stick with that? 220 MR. HAUSMANN: I would say just carry on. 221 MR. BETTS: Yes, don't be restricted by that. It looks like we, perhaps, got the afternoon available, so let's make sure we cover everything this morning, and take our time in the questions and answers. So please take the appropriate length of time. 222 MR. ADAMS: I want to thank the Board for an opportunity to participate today and present the views of Energy Probe. 223 When the rescheduling happened, we looked at the schedule and observed that we were on a panel where all the other members of the panel were utility representatives, directly or indirectly. For those who are wondering about the organization of the panel, I want to lay to rest any rumours that may be out there that Energy Probe has overtaken and acquired Duke Energy. It seems to us that the organization of the panel is just a reflection of the continuing wisdom of the Board, seeking to balance the perspective of the utilities with a consumer and environmental representative. 224 For those of you that are relying on a pure diet of PBR, I have to disappoint you this morning. My comments are going to stray from PBR in some respects, although I will comment on them. 225 Just as an overview, our intention is to try to provide a forest-and-trees observation about what's going on with gas distribution utility regulation in Ontario. I want to make a couple of observations about large-scale industry trends that may have an influence on decisions that the Board has to make in future. I want to identify some areas of existing practice in regulation that Energy Probe feels need particular attention. I've got a couple of brief comments on the consultant's report and some conclusions. 226 My experience with regulation suggests that it's often difficult for regulation to keep a "forest and trees" perspective on what is going on. Our view is there is a lot of things that are going right about the way we regulate the gas LDCs. We've been able to establish a financial solvent industry with a very large investment without incurring any public expense or risk to the public purse. We have enjoyed stable and relatively low rates for distribution services. If you look at the inflation adjusted delivery service rates, they're pretty solid going back quite a long period of time. I think, in general, the industry has also established a high standard for reliability in other forms of customer service. 227 So it's got a lot of things going for it, and it's particularly in stark contrast when we contrast the experience we've had with gas versus what has happened in electricity. 228 So I come to these recommendations for changes and some thoughts about things to think about in the future and whatnot with a voice of caution, and that is that when you're improving a good thing, it's different than fixing a problem. So we've got to keep this in context, we've got a lot of things to protect in terms of progress so far that we don't want to throw out the window. 229 Now, here are a couple of observations about things that I think are going to impact the distribution industry in the future. One is the impact of intelligent metering. As everyone in this room is aware, there is a major initiative underway that is going to -- well, literally in a very short period of time, transform the metering technology for the vast bulk of electricity consumers in Ontario. And it's not a project that's without its complications, but of all of the initiatives in electricity that are going on, I think this is one that we have reason to be most optimistic about in terms of its long-term benefit for consumers. So while this huge transformation is taking place in another energy delivery business, it, I think, behooves us to be mindful of this trend when we're considering the future of gas. 230 One observation to make about the metering technologies that are out there and being discussed and implemented, and are actually up and running, is that the smart technologies are multi-utility meters. There's a lot of reasons to do that. The incremental costs of adding additional functionality once you've gone to the effort of installing a communication device with the digital measurement and storage, the incremental capabilities are relatively modest in cost. I'll observe that we have utilities that are now implementing devices that are multi-utility meter measurement, and some of these leading utilities are now treating water measurement with a much higher degree of resolution and data care than we currently apply to fuels like natural gas. 231 The smart meters have a potential to provide a lot of benefits to gas customers, and I think some of those benefits include improving the fairness of the PGVA allocations, in fact, wiping out the necessity for PGVA. There are, we think, some substantial benefits from the DSM perspective. And also changing the whole commercial interaction between customers and upstream producers in terms of providing alternative measures for hedging. 232 So what to do about this in the terms of gas utility regulation. I think one thing we might want to do is have a look at the way we depreciate meters and associated systems to make sure that we are not blindsided by some costs coming up in the future. And we ought to look at the way we handle customer care costs. 233 Another trend, and this has been discussed by others, so this is not something new that I'm trying to introduce into the discussion, but I think it's really important and I've got a couple thoughts so I thought I'd throw them at you. One is the impact of declining customer volumes. This is a major trend. It's not something new. It's been going on for a long time, at least going back to the, I guess, mid-1980s. I don't have the data in my head, but it is a long-term trend. One thing to observe about it is that during a lot of this period of declining average uses at the small-volume customer end, the gas market was gaining different end uses. So that suggests that the trend is, perhaps, a very powerful one. It is likely to influence the long-term business conditions of the distribution utilities. 234 So there's a situation where I think this is something that -- I mean is basically a good thing, unless there are instances where there is load switching. If there is erosion of water-heating loads to electricity, for example, that wouldn't be a good thing, but certainly from an environmental point of view, most of this declining customer volumes is a good thing and we should encourage it. But we have to accommodate it because of the way we do regulation now is not totally fitting with a world of continuous decline. 235 This is an area where I think some quantitative research is justified. The Board is well placed to undertake such an effort, and it could help and provide guidance to the decisions that will have to be taken in future. We need to understand the causes in better quantification. One suspicion I have is that the DSM programs that we have are not one of the of the prominent drivers, but that's something that needs to be better quantified. It's a prima facie case now, but there's research to justify it, I think, needed. 236 Here are a couple of areas that we think need improvement. This is one that -- that's a constant -- I mean this is something that we're never going to be perfect at, but needs constant attention, and that is finding ways of lowering the cost of capital. Capital is one of the largest input costs for the very capital-intensive business that these LDCs are in, and from a customer perspective, finding smart ways to access markets, get the capital that we need, is something that should be a continuing priority, something that should never leave the Board's mind. 237 There are -- I've got a couple of thoughts on how we could address this. One thing is to encourage utilities to find smarter ways of structuring their business. It occurs to me that income trusts are one example. In B.C. recently, there was a decision against it, but that shouldn't rule out the potential for exploring those potentials here. If somebody could come up with and demonstrate that our utilities are not efficiently scaled, that regional utilities like in the instance of Enbridge, where it's got all these different delivery zones, is -- it's certainly possible that at some point in the future, somebody might be prepared to take a risk on horizontal unbundling, then I don't think that the Board should stand in the way of potential benefits that might flow from such an admittedly heavy scale of restructuring. 238 I think that along the same line of lowering cost of capital, one thing that we've got to do is cut avoidable revenue risks to the utilities. Utilities shouldn't be at stake for weather and the current rate structure imposes that risk, and inappropriately so in my view. 239 A great relief to those that just needed another dose of PBR, finally, a few comments on PBR. 240 I don't know, I continue to believe that PBR, done right, is a good thing. We've had some terrible experiences, but not that terrible. But we've got some things we've got to get over before we can go forward. 241 I think we -- now is a good time to - I mean, we are in a cost-of-service regime - set the foundation for PBR in the future. We're big supporters of a stripped-down, simplified RPI-minus-X rate-cap-type structure. There are definitely going to have to be tweaks to make it acceptable for all sides. But we find that the rate-cap structure rather than a revenue-cap structure is the starting point to go forward on a discussion. 242 Something that can help, and is just not ever going to hurt us, is to keep up our movement towards unbundling. It's a long-term historical trend. We've made a lot of progress in unbundling. Even if we don't do PBR in the near term, unbundling has inherent benefits to the regulatory process, so unbundling needs to be in there. 243 In terms of candidates for PBR, I think the best candidate is Enbridge. The primary difficulty I see with Union PBR is that, since Union is, de facto, Ontario's non-independent system operator for the gas system, because of the nature of its business, it makes the issues around access - a lot of non-rate issues, policy issues related to the functioning of that utility - from the perspective of its diverse community of shippers that it serves, inherently difficult. And so some steady level of regulatory oversight is going to be needed to continue to provide oversight for the non-rate functions. 244 In terms of the future of regulation, I think we should pay continuing attention to quality of service, not because there is a big problem with quality of service right now, but having baseline data and an understanding of the trends in quality of service is something that's an essential input for a successful PBR. 245 I think that it's appropriate to consider DSM as really a quality-of-service type of issue. I think that's a way of putting some appropriate boundaries on DSM discussions, so that they don't take over the whole regulatory discussion and then keep -- so we keep a kind of forest-and-trees perspective on the role of DSM in the context of the wider regulatory requirements. 246 Another area that we need to make progress on, whether we go for PBR or not, but particularly if there's an ambition to attempt some kind of PBR in future, is, we've got to pay a little bit more attention to this affiliate-transaction thing. Affiliate transaction is really the major problem that crashed the -- well, that damaged the reputation of PBR in the Enbridge case. And I think that intervenors bear some responsibility for not being astute enough in keeping an oversight as, I think, the Board does, and deserves some attention in this area, as well. We didn't do our job quite as well as we should have on some major affiliate transaction issues. I, for one, am kind of embarrassed about that. In terms of proximate priorities, I think, getting regulatory authority reasserted over the bills of a monopoly distributor, in the case of Enbridge, should be a priority. 247 Winding down here, but no sermon from Energy Probe would be complete without some statement about the benefits of due process, and the necessity of not throwing it overboard. It really does work. It benefits everybody, in the long term. It has some uncomfortable aspects to it, but it really is worth the hassle. It has a proven track record to the concept, and it has worked very well for the Energy Board. 248 Just on the money, numbers, I think there's lots of ways of, at a very kind of high level, demonstrating substantial benefits. It is costly, there's no question that it is costly, and often the costs are indirect costs that are imposed on all the participants, utilities and non-utility parties, that are active in this weird world. But it's something that does work, and we would be really doing a disservice to turn our backs on it. 249 In terms of just a couple of brief comments about the consultant's paper. I was, I think, quite impressed with the consultant's paper on the subject of system gas, in many respects, somewhat less impressed with the consultant's paper on regulation. A couple of ones that really jumped out at me are, there is extensive discussion in the paper about the PBR plan from the LDCs. The elephant in the living room kind of got unnoticed in that discussion. 250 The major point about the -- the major customer impact of the first PBR plan was that it allowed distribution rates to almost double for customers, so there was just an absolutely gigantic consumer impact, and very little consumer gain, from that first PBR plan, and somehow that just got missed in the consultant's paper. There were comments, also, about purchasing strategies that I think are difficult to follow. 251 So the conclusions that I have to offer are modest ones. I think if, as a result of this process, we decided that it was better to just stick with the status quo, that wouldn't be a terrible decision. It would not be at all wholly negative, by any means, and I think it's a very worthwhile exercise to stop and think about what you're doing at, kind of, regular intervals. 252 So I'm not criticizing the Board Panel at all for undertaking -- opening up the opportunity for people to, kind of, provide their input, and whatnot. But if, at the end of it, you started feeling, Gee, you know, we've got a lot of other priorities, we maybe can just leave this one alone at this stage, I, for one, would not be jumping all over you. That's it. Thanks. 253 MR. HAUSMANN: Questions from the Board? 254 MS. CHAPLIN: Thank you. Cynthia Chaplin. 255 Mr. Adams, I just have a couple of clarifying questions on some the major areas you covered. Under "Intelligent Metering," you suggested that two things that the Board should look at were the depreciation of utility meter assets and customer care costs. Could you elaborate a bit in terms of what you think -- what sort of work you think needs to be done there, and who should be doing it. 256 MR. ADAMS: Well, the current approach to depreciation is an engineering-based approach, and we might want to consider obsolescence for -- as an input in the depreciation considerations. I suspect that, whether or not the customer that's taking 1,000 cubic metres of gas per year, 1,500 cubic metres of gas per year, is ever going to get benefit from a smart gas meter, that's a question that the Board doesn't really have to grapple with too much. But there are lots of intermediate sized customers. You get into a customer that's using 5,000 or 10,000 cubic metres a year, and there may well be benefits. So obsolescence needs to be considered in reviewing the depreciation schedule. 257 On customer-care costs, I think that's an instance where we might want to think about unbundling. If there are other service providers that come along and want to package up services that are associated with smart meters and more intelligent management of resources of one kind or another, the unbundling of customer-care costs so that we can appropriately move those costs around without messing up everything else is maybe a worth while exercise. So I made a general comment about the advantages for the process of unbundling in terms of transparency and customer empowerment, but customer care is one specific area. 258 And in the instance of some of the -- like in Enbridge's case, there's already a high degree of structural unbundling for some of those costs so it shouldn't be a hard job. 259 MS. CHAPLIN: Thank you. 260 And with respect to lowering the cost of capital, you suggested that there might be room to incent more efficient capital structures and perhaps be, at the risk of putting words into your mouth, be more receptive to alternative structures. Do you think that's something that the Board should be incenting in terms of expressing a willingness to entertain those ideas or do you think the Board should be actually indicating where it thinks improvements could be made? 261 MR. ADAMS: I think the latter choice is too hard for the Board, and the utilities have the incentive and the brain power to explore those possibilities. That's -- it's a very heavy subject, right, and I would just hesitate to have somebody from outside of the utilities trying to tell them how to structure themselves. 262 I think this is something that is a shareholder responsibility. They should take on the challenge of trying to come up with proposals. But if the Board was to inform the process by some clarity about how these things might be treated in future, it might help. And it may be that such a heavy change would not be without risk, and so the risk would have to be reflected in a rate plan, but I think it makes sense to stay open to these things. 263 There are other places that have long-term PBR plans that were part of major industry restructuring. So in some electric utilities, for example, where transmission became an unbundled function that was hived off and acquired by a dedicated transmission firm, that was facilitated by a rate plan that allowed the transmission company to make investments with long payback periods to recover the efficiency gains. 264 So I think there may be aspects of the LDC businesses that might be suitable for considering in such a light. I can't speculate on what those would be, but there's lots of people much smarter and more experienced out there that may have innovative ideas and I just don't want those ideas to be shut out in this process because of its structures. 265 MS. CHAPLIN: And do you see that ability to innovate, or incentives to come forward with some innovative ideas? Do those incentives differ whether we're under cost-of-service regulation or PBR or do you think it could be possible under either? 266 MR. ADAMS: Well, I don't see PBR and cost-of-service as two completely separate universes. They have a lot to do with each other. But in general, where risks are greater and investments are needed to get payoffs in longer time horizons, then the time element has to enter into the rate formulation process. So I think that it behooves the regulator from the process generally to remain open to flexible thinking about temporal horizons for rate plans. 267 MS. CHAPLIN: Thank you. 268 MR. HAUSMANN: Mr. Betts. 269 MR. BETTS: A couple of -- yes, sir. Yes, Bob Betts here. 270 First of all, I think that everybody in this room knows that Mr. Adams is not one that's afraid to express his opinion when it's known, and expresses it very directly and positively. And yet in this case, Tom, I see you using phrases like, "I wouldn't be disappointed if there were no change." I see you using phrases like, "Improving a good thing is one thing, but it's very different from correcting a problem." 271 I'm sensing there is some hesitance here. I'd like to find out from you clearly: Where are you on the PBR issue? Are you saying we should be looking at cost-of-service with perhaps the modifications, corrections that you've indicated or -- I guess put it on the table for me. 272 MR. ADAMS: I'm trying to get these slides together in the middle of the night and realizing this is a heavier job than discussing some of the other issues that have been in front of this Gas Forum. System gas, to me, is a lot clearer. This is a grey area. This is -- and from a customer perspective, there was a lot of things that -- this morning about PBR by the utilities that I just profoundly, profoundly disagreed with. I think they, in several instances, just misquoted the historical record in egregious fashion. 273 So getting a starting point for how to get -- I'm a fan of PBR, but we've got some history we've got to live down and we're not making a lot of progress. Based on the presentations we heard this morning, there's -- I think we've got to make some improvements before we can make a solid discussion about how to achieve PBR. And we've got to get -- for PBR to work, there's got to be a high level of buy-in. So it's one thing to get Energy Probe to kind of theoretically say, Yeah, PBR is the way to go, let's get moving with it, but there are a lot of other customer groups that say, No way, cost-of-service is fine, it's working, it may not be perfect, we're prepared to stick with it. And that's a perspective that it's -- you know hard for me to argue against. 274 So I think I am still a fan of PBR. I want to hold up the flag, but the flag is a little wilted. So I'm thinking that in a couple of years, you know, you send the kids to sit on the stairs for -- think about what you did for a little while and have a little time out, we'll do the cost-of-service thing, and then we can hopefully grow out of that, and come up with some new strategies. But I think it's going to take some time. So I don't think PBR is -- we're ready for PBR now. I think it's going to take a couple of years, grind through some cost-of-service and then take a risk again. 275 MR. BETTS: Thank you. And now I know the position that you're taking very clearly. Thank you. 276 One other question. You referred to affiliate transactions with certainly some concern, and yet you talked about other forms of restructuring that the utilities might want to consider that could benefit costs and therefore ratepayers. Why don't you see appropriate outsourcing with affiliates as being as positive as perhaps those legal restructurings or financial restructurings you spoke about? 277 MR. ADAMS: One word, rebasing. I thought the point of PBR was, we do PBR, let them achieve some benefits, and then at the end of it, we rebase and move forward. I thought that was just so clear. And when all those affiliate transactions took place, I started wondering if I was in the right room. So much stuff was up and moving. It was so hard to figure out what was going on, and it was so clear that big chunks of the approved budgets had moved out away from regulatory purview. It became a really major problem. 278 So on one hand, I want to let the utilities be flexible in the way they restructure themselves because I am sure there is innovative ways of doing things and I really think that's -- the efficiency benefits are out there. I mean, that's a gut hunch, but I think there are. That's not suggesting that we have a lot of fat in the utilities or anything pejorative like that, but I there may be smarter ways of doing things in the future. We've got to have an approach that allows all that to happen in an atmosphere of fairness and transparency, and we've had our challenges in those two areas. 279 MR. BETTS: Thank you very much. 280 MR. HAUSMANN: Questions from the staff? 281 MR. BETTS: Those are all our questions. Thank you. 282 MR. HAUSMANN: Thank you, Mr. Chair. It's five to 11:00. So we've gone a little over time, but I think it was well worth getting through the presentations. We'll take a 15-minute break and reconvene at 11:10. Thank you. 283 --- Recess taken at 10:55 a.m. 284 --- On resuming at 11:12 a.m. 285 MR. BETTS: Can I ask everybody to please take their seats now. 286 MR. HAUSMANN: Thank you, ladies and gentlemen. I understand, as a result of some conversation over the break, Mr. Adams would like to make a correction to his presentation. 287 MR. ADAMS: Yeah, I need to correct a comment I made. I was concerned at the presentation from the utilities about their perspective of the mutual lack of trust, and one example they provided was that intervenors sought to reopen PBR plans in mid-stream. I forgot to -- I forgot about the terms of a motion that had been filed by CAC and IGUA that, in fact, did -- I'm informed by IGUA, did attempt to reopen the PBR plan. So I have to withdraw my remark. 288 MR. BETTS: Thank you. 289 Just before we get into the panel discussion with respect to this subject, I just wanted to make certain everybody understood that there would not be lunch served today; that we, in fact, will go until the lunch break and then we will break for the day. And because we have a larger panel than anticipated, it's possible that we could push towards 1:00, and I'd like to do that. I'd like to hear from everybody. So are there -- does anyone have any objections to that schedule? Very good. So let's proceed with the panel discussion. 290 DISCUSSION PERIOD: 291 MR. HAUSMANN: Thank you, Mr. Chair. The way we have conducted these proceedings in previous days is we've given the consultants an opportunity to present the first question to the panel, and then we open it to the floor. So do they have a question this morning? 292 MR. KAUFMAN: Yes. This is Larry Kaufman for Pacific Economics Group. I have, actually, two questions, two kind of schematic questions that cut across, I think, almost all the presentations. Before I do that, before I get to that, though, I'd like to correct one misunderstanding. 293 Mr. Packer said that our report said that we were recommending the possible use of X factors, and TFP studies from other jurisdictions be applied in Ontario. That's not the case. Our report doesn't say that, and I wouldn't recommend that. He may have gotten that impression from the fact that we talked about a number of different TFP studies. But just to clarify, that's not our recommendation. 294 Okay. The two questions I have are related, and they both get to rate-making and the rate-making mechanism, and the first one has to do with the rebasing issue. A number of opinions have been expressed on rebasing, and we've seen, kind of, two ends of the spectrum: One is a full cost-of-service based rebasing of rates, which is Energy Probe's position, and the other is no rebasing of rates based on cost-of-service performance under the PBR plan, which I gather is both Enbridge and Union's position. 295 I'm wondering if there is a middle ground that might be acceptable. For example, you could have a weighted average of cost-of-service filing, and you could have also a formula-based adjustment and you could have, say, an 80/20 weighting. I'll just throw that out there as an option, and wonder if there's any sort of agreement that can be reached on that. 296 I realize that that wouldn't get away from the issue of the costs that are imposed by cost-of-service filing, but I'm wondering just how burdensome a new cost-of-service filing would be if we had, say, a five-year term for a PBR plan; in other words, there would only be a cost-of-service filing every five years as opposed to now, where it's essentially annual. 297 My second question is related, but it gets into not so much the update of the PBR plan but the formula itself. And my understanding is that there seems to be a desire to have a very simple sort of formula, and I think Enbridge had a very interesting bullet point under their desirable PBR attributes, which was that there should be an outcome-oriented interpretation of just and reasonable rates, and I'm interested in finding out what you mean by that. 298 There was some discussion about having a discount factor applied to the CPI, and I'm wondering how or what would be a just and reasonable discount factor, and if you have any standards for interpreting the just and reasonableness of a discount off of CPI without going to consideration of productivity evidence, and things like that. 299 So those are my two questions. 300 MS. HARE: Marika Hare for Enbridge. 301 I wanted to jump in because it gives me an opportunity maybe also to correct something, or the impression I may have left. 302 Within any PBR plan, one of things I stressed was to understand the rules going into the plan, and so when I was suggesting that there doesn't have to be rebasing, that's exactly that. But I don't think it's essential. But, for example, in our targeted PBR plan for three years, there was the understanding that at the end of the three years, there would be full rebasing. So again, it goes back to how this is set up at the outset, and understanding whether or not it's a requirement, there's agreement that there be rebasing, or that there doesn't need to be and that the plan can continue. 303 But to your specific question about this weighted average cost of service and formula, we think that's a very interesting idea. We have looked at it, thinking it achieves many of the benefits of assuring all parties that there is a review, but, on the other hand, it's fair to the shareholder, because any of the efficiencies that are gained are not immediately given up so that there is this incentive. Whether the weighting is 80/20 or 75/25, 50/50, whatever, the concept we think is something that is of interest. 304 In terms of your second question about simplicity outcome oriented not just inputs, we think that most of the stakeholders, what they're really after are rates that are fair and predictable. And so if what you're really after are rates that aren't increasing by more than, say, half of inflation, 60 percent of inflation, that's the outcome, and that's what most stakeholders, we think, want to be able to tell their clients. 305 So how to figure out that discount, what we did in 2004 is looked at history in terms of how our rates adjusted against inflation, and came up with the percentage discount. But I think there are some ways to do that and still keep it simple. 306 I think maybe Rick Campbell from Enbridge wants to add to that. 307 MR. CAMPBELL: Yes, thank you. Rick Campbell from Enbridge. I've been involved in some of the PBR research in the utility, and particularly the discussion of stakeholders. And Mr. Kaufman is right, we put a big premium on simplicity in our recommendations; one, because we think it helps everybody understand what's going on, and also helps there be no surprises, I guess, about outcomes that were as a result of complexities of design. 308 A very well-regarded PBR expert in the United States recently made the observation to me that he thought PBR plans were, in the United States at least, inversely related. The quality of plans were -- 309 MR. HAUSMANN: Mr. Campbell, sorry, could you speak more into the mike. People are having a hard time hearing you. 310 MR. CAMPBELL: The quality of plans were inversely related to the number of Ph.D. economists on commissioned staff. Now, he himself is a Ph.D. economist, I'll have to say. But I think it just goes to the theme that theoretical purity and, really, good outcomes for regulators and customers and utilities needn't be consistent. We can approach the topic in relatively simple terms and deal with it that way. 311 On the question about just and reasonableness, again, just to support Marika Hare's observations, I was just looking for a new interpretation of the standard. It's very well defined under cost of service, but if the Board is going to make a leap to the PBR environment, and in the past the standard has been tested by cost-of-service detail and cost-of-service review, then some thought would be helpful and some outline of the Board's criteria under the PBR regime, what would be helpful to guide all players as to what's successful and what's just and what's reasonable in terms of rates. If it's an external benchmark simply like relative to inflation, or what's going on in other industries, all that is helpful. 312 MR. HAUSMANN: Any comments from others on the panel? 313 MR. PACKER: Mike Packer, from Union Gas. 314 I support the comments that Marika has made. In terms of rebasing, I guess I'll take you back to the question we were trying to get the Board to look at in the context of establishing the rate-making structure for Ontario, and that is, what is it that we're out to achieve here? 315 If we are embarking on kind of a traditional PBR-type environment, in that context, we just don't see the need to revert back to the detailed cost-of-service, including the phase 2 piece of the equation in terms of a detailed cost allocation rate design process. If what you're trying to do is generate a regime that has price predictability and stability for consumers, and you recognize that PBR is a movement away from rates that reflect cost, in terms of providing some of the efficiency gains back to ratepayers, I think there's merit in that. It's just a matter of whether that's already been achieved by establishing a fairly high X-factor on the outset or whether you need to do something fairly explicit at the end. 316 In terms of the comment about whether we should apply a discount factor to CPI in establishing how prices are set between cost-of-service filings, I guess I just note that target rate of inflation is 2 percent. How much different are we going to be from that is a question, but how much can we actually have it as a departure between our cost structure and rates if we're talking about 2 percent? In terms of our suggestion, the Board could consider a very simplified approach. In that context, with immediate earnings sharing, we don't think the discount rate being applied against CPI is really required. 317 MR. HAUSMANN: Mr. Hoey. 318 MR. HOEY: The only comment I would have is that, from my experience with cost-of-service studies and past experience, is that it's the comparability factor from year over year, or time period to time period. And if you're going to allow the utilities to make productivity gains and do things completely different than they did yesterday, it becomes almost impossible for them to mirror what they were doing yesterday and somehow have a comparative cost structure between the two periods. 319 So that, I think, is going to be a disconnecting point if you have a PBR system and then you want to keep comparing, let's say, from 2002 to 2005, and 2005 has to compare to 2010. It's just the companies should be different in 2010 significantly enough that there will be a lack of comparability. 320 But I think I agree with Marika and I think that's one of the things I said earlier was that we have to agree up front what information you want to compare if you are going to go back and look at it, and compare up front, compare in the agreement going into the thing rather than after the fact. That way data is collected at the beginning and through the period, and I think going back after the fact looking for -- well you used to provide this. Well, yeah, but we didn't agree that we provide that at the beginning. So a lot of thought on all parties is needed for what information is critical for rebasing or future setting of the next PBR agreement and/or where you go after that. 321 MR. ADAMS: Just one comment. 322 MR. HAUSMANN: Tom Adams. 323 MR. ADAMS: Tom Adams. 324 To contrast the general support, I think, that many people have spoken of about the advantages of a simple formulation or a regime versus the added complexity of a weighted treatment at the conclusion of the regime for rebasing on a cost-of-service basis versus a non-cost-of-service approach. I mean there's always these trade-offs, but seems to be particularly stark in your formulation. 325 MR. HAUSMANN: So for those of you who do not have mikes at your chairs, there is a mike here that is reserved for the Q&A session but there is many seats here. Feel free to come up to any one of them with the mike and ask your question or make your comment. Anybody out there? 326 Mr. Shepherd. 327 MR. SHEPHERD: I have four questions. First is for Ms. Hare. On Thursday, Mr. Ladanyi talked about the -- he was talking in the context of storage about the ownership of utility assets, but really fundamentally underlying that is the, sort of, philosophical question of whose business is it. And PBR is all about how much are the utilities allowed to make. You will recall his analogy to the Starbucks franchise and that sort of thing. Can you comment on how that philosophy relates to this PBR discussion? 328 MS. HARE: Let me first comment on what Mr. Ladanyi was saying, and I guess there are several ways I can comment. And the first way is the fact that Tom Adams actually gave the answer this morning when he talked about $7 billion of investments, none at public expense, he said, or risk, which I think just reiterates the point that Tom was making last week which we believe these are the shareholders's assets. The shareholder invests in the assets, not the ratepayer. So our company's position would be, and he was specifically talking about any disposition of assets and who gets the proceeds of those assets, and the company would argue, and I think supported by regulatory precedent and I'll get to this in a second, that those proceeds go to the shareholder. 329 In terms of regulatory precedent, I guess the analogy I'd make to discussions about incremental versus rolled-in tolls was the argument sometimes being made about whether historic users have any vested interest in those assets. And so on transmission lines, they have argued in the past, well, and I might say it was Consumers Gas arguing against the NEB last I recall in the '80s, and Consumers Gas lost argument, where the Board said that historic users do not have any vested interest for roll-in tolls. 330 I guess the last comment I'd make about who owns the assets is that the fact that Consumers Gas has been sold many times, for even the last 15 years, at a significant premium. That purchase price discrepancy did not go back to the ratepayers and the shareholder doesn't earn the return on that goodwill that was paid, which I think, in my mind, just proves that the assets are owned by the shareholder. 331 Now, how that relates to PBR. In PBR we're talking about earnings as a result of rates and efficiencies that management takes, and I think our position has been consistent. We do believe in earnings sharing during a PBR period. 332 MR. SHEPHERD: Second question is for Mr. Campbell, I think, or it might be for you as well, Ms. Hare. You're talking about the -- about splitting up the concept of cost and the level of rates, disconnecting them, and I guess -- we, by the way agree with that. But I guess the concern is there is a very fundamental principle of rate making, it's the basis upon which we define just and reasonable rates, which is that you balance how much the shareholder gets and how much the ratepayer gets. And it seems to me, and I'm asking you to comment on this, whether implicit in the notion of the disconnect is that you reject that principle because you're no longer going to consider the cost side of the equation. 333 MS. HARE: Well, I'm not sure -- repeat that again, please. Not the whole question, what's the principle? 334 MR. SHEPHERD: The principle is that whatever the benefits of the franchise are, they're split. The shareholder gets a fair rate of return, a fair amount of it, and the ratepayers get the benefit of the franchise that they've funded, and that balancing of interest is essential to rate making; right? 335 MS. HARE: No, I don't think that's a principle of rate making. The principle of rate making is that the utility earns a fair rate of return on its investment and the management of the utility and, in response, the rates are fair to customers. Now we're talking about PBR where the risks and rewards are changed, and the issue is should there be earnings sharing in what's returned to the ratepayers. 336 I mean, there's a very good theoretical argument that, in fact, nothing goes back to the ratepayers. During the PBR period, the utility is allowed, in exchange for taking on additional risk, to earn whatever it earns. That's a more difficult concept to sell and, I think, the reason that Enbridge is quite adamant about earnings sharing is because under the -- our experience under targeted PBR was that ratepayers felt they got none of the benefits. Then we've got the Enbridge pipelines example which does have earnings sharing, 50/50 sharing, and all of the parties in that process believe that it was a very fair process. And, you know, when you're really talking about negotiating with your customers, you want them to feel that it's fair, and that the rates are fair, because that's who we're negotiating with, is our customers. So I don't think it's a principle of rate-making, I think it's a -- I'm not sure it's a principle, at all. Let's just call it a mechanism by which the rates are set, and that there is an agreement of sharing. 337 MR. SHEPHERD: The third question is for Mr. Packer. You talked about a multiyear cost-of-service model, but it sounded like you were saying cost of service and then CPI for five years, or something, which sounds to me like PBR. So I guess my question is, why couldn't you just do a five-year cost of service? Just, like, do a budget for five years, figure out how much it's going to cost to run the utility for five years, come in with a rate case that says we need these increases over five years; you could do that, right? 338 MR. PACKER: No, we couldn't do it very easily. Right now, that would exceed our detailed planning horizon. And, from my experience, that would turn into a very large cost-of-service hearing, where we would be discussing things that are -- in the context of when you'd need to file a rate case, it would be a year in advance, so you would be talking about things that are five or six years out, and I don't think that is a very useful exercise in trying to guess at what's going to be the utility's cost, or through-put structure, that far out in advance. 339 MR. SHEPHERD: And the last question is for Mr. Adams. Mr. Adams, you talked about sending the kids for a time out in the context of the sort of distrust and difficulty that we had with PBR, and I guess the obvious question is, who is it you're referring to as "the kids"? The utilities, the ratepayers, or both? 340 MR. ADAMS: I just sent myself for a time out there, so I have to have some humility about this. No, I think the process is going to take a little while, and coming up with appropriate rules for affiliate transactions can occupy us during the inter regnum. 341 To be successful, there is going to have to be some level of negotiation, so it's like all the negotiating parties have to be able to come to some kind of reasonable deal. And, from the comments that have been prefiled in this process, I think from the customer side there is not much willingness. There seems to be much more interest from the utility side. But I think that's going to take more time. 342 If I could, I'd just comment very briefly on the first two questions that Jay put on the record, and his question to -- Marika's first question was on the disposition of assets, whose business is this, and Marika responded with regulatory precedents. I just throw out that we've had regulatory precedents in recent years, like the disposition of excess property, that have taken a different approach in terms of a sharing-charges-based approach. 343 And Jay also asked a question about the relationship between costs and rates, and as you move into PBR, you drift somewhat away from cost-based rates. My only comment on that is that there's a limit to how far these things can -- costs and rates can drift apart without creating a lot of risk and potential problems down the road. If you take a long enough time horizon, a cost-based perspective becomes very central to the ultimate costs. 344 MR. HAUSMANN: Anybody else? Comments, questions? 345 Julie and -- somebody else beat you to it. 346 No, it's fine. Carry on. You're there. 347 MR. STACEY: Jason Stacey, representing Sithe Canadian Holdings. 348 Mr. Hoey, you had talked about customer PBR expectations in terms of cost savings and balance -- 349 MR. BETTS: Just before you go any further, I've noticed that that microphone gives us more feedback than others. It's not necessarily you. So let's switch the reserved seat to the one beside Mr. Adams, and I think that might perform a little better for us. 350 MR. STACEY: Okay. Mr. Hoey, you discussed customer PBR expectations in terms of more cost savings, transparency, and more balanced approach. I'm wondering, in terms of when you talked to the customers, was there any comments in terms of new services and products from the utilities under a PBR approach? 351 MR. HOEY: Patrick Hoey. Specifically, no, those weren't raised with the groups I was talking to. Obviously, I think, with a representative like yourself, they would be looking for innovative new products as well. That's where part of that flexibility, I think, of a PBR would allow them. 352 What I meant about savings was that it has to be something tangible that people can latch onto. It can't be, Well, your rate is lower than what it otherwise would have been. That doesn't tell them how much they saved, and I think that's what the customer groups are really looking at, from that perspective. But I think, with a PBR mechanism, I would hope that it would allow for the utilities to come up with new products and services, and potentially differentiate even old-rate classes into smaller or more niche markets to -- it may not be a price thing, but it may be a service-quality differential between a certain group of customers, even though today they're grouped as, let's say, either general-rate customers or industrial customers. 353 MR. STACEY: Thank you. We've heard of various different approaches for rate regulation this morning, and, I guess, is there one out there that would be more conducive to the development of new services and rates for customers? Or can they sort of -- can they all be workable in that regard? It's just sort of open for the utilities and anyone else on the panel. 354 MR. HOEY: I guess before the utilities speak on their behalf, just -- my past experience is that cost-of-service regulation, in introducing any new kind of rate class or service, is a long, drawn-out process, and somewhat frustrating for customers, especially if they're new customers. I know my experience -- it took upwards of over two and a half years for a new service to come on board with Centra. And the frustrating part for the customers is they wanted it in six months, at most, and -- but, to go through the regulatory process of reestablishing a new rate class, maybe not getting the initial decision just right, going back and having to redo it again, restructuring everything, it's a long, drawn-out process. And therefore, the utility is not capable, under cost-of-service, to do it in a timely fashion, or as timely as customers would want. 355 Under PBR, I would suspect that there would be -- it would be easier to come in in a shorter time frame and, therefore, at least, meet that customer perspective better than in the past under cost of service. 356 MR. HAUSMANN: Any comment from Union or Marika? 357 MS. HARE: Marika Hare from Enbridge. 358 Actually, in theory, I don't see that it would make any difference at all. As soon as you have one new rate class, the other classes need to know how that affects them. And why is there a rate class? Are the principles of cost-causality incurrence properly being accounted for? It shouldn't make any difference whether it's cost of service or PBR. 359 MR. PACKER: Mike Packer from Union Gas. 360 I agree with Marika's comments and Patrick's as well. PBR versus cost of service is intended, I think, to primarily be the mechanism on which you set your prices. The introduction of new services shouldn't be directly related to each or either of them; however, if you're under a regulatory structure that provides the ability for the utility to focus its resources on other things other than the regulatory process, that should result in new services being developed. 361 In the presentation this morning, I tried to identify that one of the components of our simplified approach would be that we'd have annual or semi-annual meetings with customers to try and identify what they'd like to see happen in terms of non-rate-related issues. So that would be one of the benefits of a more streamlined regulatory process which can exist under PBR or cost of service. 362 MR. STACEY: Anyone else like to comment? I guess the last question. In terms of further rate unbundling, does one of the forms of regulation support that better than the other? 363 MS. HARE: Marika Hare. 364 It doesn't look like anyone is too keen to answer. I haven't given that a lot of thought, Jason. My first reaction is, I don't think it makes a lot of difference but maybe that's something we can give more thought to and address it in the November 10th submissions. 365 MR. ADAMS: My own view -- Tom Adams -- is that PBR worked better in the -- all else equal, in a more unbundled environment and was better disaggregation. But that doesn't mean that in cost-of-service unbundling is not justified, but it's a more essential ingredient for successful PBR than in cost-of-service. Cost-of-service you have other tools. 366 MR. PACKER: Mike Packer, Union Gas. 367 I'm not sure I have a whole lot more to add other than it may depend on the type of unbundling you're asking for. I think it really comes down to what are your resources otherwise doing, and if there are resources available and you're looking for innovation in terms of service offerings or unbundling, you have to have the resources available to look at that. But again, my earlier comment was I think that can be achieved under cost-of-service or PBR. It's just a matter of streamlining the process. 368 MR. STACEY: Just to follow up on that, Mike. I'm stretching my memory here a bit, but I had thought that Union's PBR in unbundling were tied together originally. 369 MR. PACKER: That's right. It was a common filing. 370 MR. STACEY: But they were linked in terms -- in terms of -- how would I say it. Maybe the lead-up to it or I think the market wanted to explore unbundling, and I think Union was willing to accommodate that with a PBR approach to go along with it. But maybe I'm not -- my memory isn't serving me too well. 371 MR. PACKER: Well, you are correct. Our original PBR proposal was made in the context of an unbundling proposal, and at the time we thought there was some value in packaging them both together. I guess we've had the experience of now living with PBR for three years, and I'm not convinced that you necessarily need to have PBR in order to have innovative service and product offerings. 372 MR. STACEY: Thanks. I remember now. It was a package arrangement or package deal. Thank you. 373 MR. HAUSMANN: Thank you, Mr. Stacey. 374 Ms. Girvan, come right to the front, please, and I would just remind the panel that it's tempting to look at the questioner but we're speaking to a whole room and to the whole webcast, so please be sure to speak into the mike. Thank you. 375 MS. GIRVAN: Julie Girvan for the Consumers Council. 376 This is primarily for the utilities. Last week, we heard about some, what I would call, fundamental proposals or proposals to fundamentally change the industry. And those include restructuring the storage market, changing the way it is priced, recosting system gas, different levels of that, and restructuring system gas altogether outside of the LDC. I'd just like to get your views on how you see your proposals for either a multiyear cost-of-service or incentive plans fitting into the, sort of, resolution of those other issues. And I'm sort of looking at, do you think that they need to be resolved first or can you see these proposals for multiyear plans being undertaken at the same time as these other fundamental changes to the industry? That's my first question. 377 MR. CAMPBELL: Rick Campbell for Enbridge. 378 Some of the earlier papers you could see published on PBR suggested that PBR is something best for a stable-state industry. You don't want a lot of cost uncertainty in a PBR environment. And I guess it's our view that if that's the case, PBR may never be implemented ever again because we just don't seem to have a stable industry. There will be changes, the utility might well prefer to have some more certainty about costs before it actually makes application for a PBR plan, if, in fact, there are some significant changes to the industry structure coming down the pike from the Board. But on balance, I think we look forward to the opportunity under a more flexible, performance-based regulatory plan to make the changes that we think are best for both the customer and the business and the shareholder. 379 So we welcome the opportunity for PBR to go forward now with some guidelines from the Board and then perhaps, as we've suggested in our proposal, depending how significant the structural changes are, we might have a choice; cost-of-service for a little while until the costs of certainty about the new business environment is known or PBR. 380 MR. PACKER: Mike Packer from Union Gas. 381 Yeah, these are the same type of comments that we received when we filed our original PBR submission. There were parties that suggested the industry was changing too much to implement PBR. So in that context, I would agree with the comments that Rick just made in terms of, if you wait for the industry to be settled, you may never embark on PBR, if that's where people want to go. 382 I guess I would dispute some of the characterization that Julie made about fundamental changes in the storage markets. As you recall last week, there was an indication that we've been providing a significant amount of storage into the market at market prices for quite some time, so in that context, I'm not sure that I see that it's a fundamental change. And I guess the system gas issue, it depends on what the ultimate outcome of this proceeding is, but we're, for one, not advocating a lot of change in terms of system gas. 383 MS. GIRVAN: Mike, just to follow up on that. If there was a fundamental change with respect to system gas proposed by the Board, do you see that fitting in -- would you rather see that resolved first before moving to some multiyear plan? 384 MR. PACKER: It's tough to answer that question without knowing what the fundamental change is. I guess we always like to have as much flexibility as we can in terms of responding to change. Having said that, I think to the extent we're trying to come up with a rate-making structure here, presumably there would be some ability to handle changes that come about as a result of actions of this Board. So I don't necessarily see that standing in the way of a multiyear cost-of-service arrangement where prices are adjusted by CPI for years between the cost-of-service proceedings. 385 MS. HARE: Marika Hare from Enbridge. 386 Julie, my answer is no, I would not want to wait until the issues around system gas or storage are resolved. We have rates in place for 2005 as you know. We're turning our minds to the 2006 application. Some of these issues may be resolved in a more timely fashion, and I think storage, for example, will probably be a longer time horizon. And it goes back to Rick's point about a static utility. I don't think such a thing exists, and so what we're saying is that the PBR plan has to be flexible enough to incorporate whatever changes occur. It might be changes to system gas, it might be storage, it could be something else, it could be, as you mentioned, an acquisition, it could be a merger, but these will happen. And so the PBR plan has to accommodate all of these, some of which, you know, we've identified and are discussing, but others we haven't talked about but I'm sure will come forward in that five-year horizon. 387 MS. GIRVAN: Just one more question. I guess this is really for the utilities again, but Tom, you might want to chime in. I think you raised the issue. 388 Do you have any proposals that, I think, sort of looking back on the way we've dealt with DSM over the past 10 years in the regulatory context, and I just wondered if the utilities had put their mind to how we might deal with that, considering in the past, under PBR, we've had DSM dealt with on a separate sort of stream, outside of the normal PBR issues. So I'm just wondering if you think there needs to be some changes, and, potentially, what those changes might be. Thank you. 389 MR. PACKER: Mike Packer for Union Gas. 390 I'm not sure that I turned my mind to how DSM should be structured in the future. I guess I would note that we did have a DSM plan in place while we were working under a three-year PBR plan, and, subject to the normal discussions we have about targets and free-riders and DSM-related matters, I don't think there were many new challenges that were introduced as a result of being on a multiyear pricing structure. 391 MR. HAUSMANN: Anyone else? Tom? 392 MR. ADAMS: It's a hard question, a good question. I can't think of anything useful. 393 MS. HARE: Marika Hare. 394 I wanted Tom to go first. I was convinced by Jack Gibbons last week, hearing what a great success DSM's been in the last 10 years. I think DSM probably should be handled outside of the PBR plan, the way it was in our targeted PBR plan. There are some other items that would be handled outside of the standard PBR plan. I'm thinking, for example, those that already have a sharing formula, such as transactional services, for example. Since there already is a sharing, I mean, if we agree on a mechanism for PBR that has a 50/50 sharing, that would have to be taken into consideration. But I think DSM has been working well and outside of, at least in our case, the targeted PBR, so I would see that there would be that exception as well. 395 MR. HAUSMANN: Ms. Allan? 396 MS. ALLAN: A question for Tom -- it's Judy Allan. 397 Tom, you mentioned the need to accommodate the declining-use factor in Ontario, and so I was surprised when you opted for RPI-minus-X as opposed to a revenue cap, because I think a revenue cap handles a declining-use factor much more usefully than an RPI-minus-X does. I just wondered if you wanted to comment on that. 398 MR. ADAMS: Revenue cap has other characteristics beyond just dealing with the volumes question. What I was really focused on in recommending price cap versus revenue cap was the efficiencies focused on the delivery service itself. I think there are other ways of dealing with the declining use that -- leaving aside price cap versus revenue cap, and I think the Board deserves some credit for moving in this direction in recent decisions. And I'm thinking, primarily, about decisions that have moved us towards a higher recovery of attachment costs than the monthly customer charge, which have been beneficial to the utilities from the perspective of revenue stability. That's incremental progress, and it's an example of something that I think was a good way to go. 399 But revenue cap would be a very fundamental change in approach. It would have benefits from a declining-use perspective. I accept that observation. But declining use is only one of the issues that the utilities have to take into account. So, in the context of incentives for efficiency, that's the reason why I prefer the rate cap. 400 MR. HAUSMANN: Ms. DeMarco? 401 MS. DeMARCO: Lisa DeMarco with Macleod Dixon. 402 My question follows up on Mr. Hoey's analogy of buying a car, thinking that the price you got was fair and then finding out the cost to the dealer. It's actually the initial presumption, thinking that the cost was fair, I assume, that is based on your comparison to other people's price for purchasing a similar car from another dealer; would that be fair? 403 MR. HOEY: No, I meant that -- I didn't mean it in that sense, in that if you'd agree to a price from a particular dealership and thought it was a fair price, but then found out later that that dealer, that particular dealer, had a special deal with their supplier and had gotten it at 50 percent less than the price you bought it, and you would think that 50 percent profit for him was way too much, relative to, say, 20, that you would be less --- you would believe that your benefit, that you're getting -- you had gotten taken for, and you wouldn't be as comfortable. Now, if you never knew what the cost was in the first place, it really wouldn't matter to you -- to whether you perceived you had a good deal at the end of the day. If you didn't know the cost a year later, you still would have thought it was a good car, regardless of what anyone else was paying for theirs. 404 MS. DeMARCO: I guess my questions revolve around - I have three - that initial assessment that the deal you got was fair. And, in particular, in a situation where we've got a monopoly, how would you suggest that all customers, including marketers, ensure that the utility's rates and services are fair? And this is, basically, a follow-up to Ms. Hare's question of the Board, looking for guidelines, for the Board to tell them how they would determine those rates, if services were fair. So I'd like to hear your perspectives on what you suggest would be fair. That's part one. 405 Secondly, I wonder what you would suggest in terms of access to information and disclosure to ensure that the Board can fulfil other parts of its mandate, specifically, ensuring competition in the sale of gas to users. 406 And thirdly, related to Mr. Stacey's questions, under a long-term PBR or long-term cost-of-service regime, how would you accommodate rapidly-changing customer needs, both electricity consumers, or customers, and marketers, that are associated with the rapidly-changing industries that they work and live in? 407 MR. PACKER: I assume your question was for anyone who was willing to answer it? 408 MS. DeMARCO: Ready, willing, and able. 409 MR. PACKER: I'll try. I guess in terms of your first question about how parties can get comfortable that our rates are fair, I'm not sure why you're asking that question. I guess, in terms of Union Gas, we just went through a very lengthy cost-of-service proceeding for 2004, where 20 or 25 volumes of material were produced which should have given everybody as in-depth a knowledge as they would ever want in terms of our cost and through-put structure. So, in that context, if you're stepping off into a multiyear pricing arrangement, I would assume that that was enough comfort that base rates are appropriate. 410 In the context of the access to information, again, I'm not sure where that's coming from. Under our simplified approach, we would have discussions with stakeholders periodically, and, to the extent parties were looking for information and it was available, we would do our best to produce it. 411 The caveat that I put around that is the discussion we had earlier about, it's sure a whole lot easier to produce information if you're collecting it as you go along as opposed to trying to come up with it after the fact. And it would sure be of assistance to the utilities to understand exactly what information would be required so that information can be collected as we move along. 412 Your last question about accommodating rapidly-changing customer needs, I guess, I just go back to my earlier comment about, if we're trying to be responsive, as best we can, to customer needs, the last thing you want to be involved with is annual cost-of-service hearings, where the hearings, themselves almost take longer than the year in which you're setting the prices for; again, trying to free up resources to actually be responsive to customers and deliver on some of their expectations. 413 MS. DeMARCO: Just before anybody else answers the question, I wonder if I could just add a clarification that we're talking about both within the term of a long-term cost-of-service or PBR regime and coming out of a long-term cost-of-service or PBR regime. How would you ensure, what would be your suggested litmus test to show both the Board and all stakeholders that those rates are fair. 414 MR. ADAMS: Tom Adams. 415 On the first question of assessing fairness, I think two comments in reply. One is due process for the process under which it is developed and assessed, and the second is rebasing. That's -- rebasing is essential to the fairness of PBR. 416 In terms of access to information, I think we have to appreciate the utilities are in a privileged position. They have the privilege of a franchise and part of the responsibility that comes with that privilege is that their businesses operate in a fish bowl. So I think there's a very high onus on them to disclose. 417 With regard to the changing customer needs, that's an instance where it's not just the utility that needs to participate in arriving at new innovations but the regulator needs to be alert to these needs as well. It's fair and reasonable -- it's an appropriate process for the regulator to receive and dispose of applications. I mean they're not initiating cases of -- for new types of service. At the same time, the regulator should have a close enough ongoing understanding of how the customers are using the system and what their expectations are, what the needs will be in future, that when applications do crop up, that it's not a big surprise to the regulator. 418 So if, for example, we've got a lot of peaking generators that want some kind of line pack related service, you want -- for a very short run, changes in output for power generation purposes, and this is big enough, a big enough deal that it's going to have an impact on the operations of the gas system. You don't want the regulator in a position where they have to bone up on what line pack is when this arrives. If this is going to be a prospect for something we are going to need a rate around -- I'm just taking a hypothetical out of the air, but you want the regulators to know enough to deal with the issues when they are presented in a fairly efficient fashion. So there is a need to maintain a very high level of professionalism, not just a passive recipient role. 419 MS. HARE: Marika Hare for Enbridge. 420 I first wasn't going to add anything because I thought that Mike put it well when he said -- when he asked the question about how it is different from today in terms of how rates and services are set and in justifying that they're fair. I mean, I don't see it's any different. But I did want to introduce one thought. 421 If in year two of a PBR plan, for example, because of management actions or some innovation that management came up with, the utility earns a higher rate of return, that doesn't make those rates any less fair than they were on the day they were set. So if, you know, if that notion is out there that it's up to how much the utility makes, I think that's a fallacy. 422 MR. HOEY: I'll just make one comment -- Patrick Hoey -- about rapidly changing customer needs. 423 If if there is long-term cost-of-service and/or PBR in terms of a structure, one alternative is to look at something like what the CRTC does with the telecom industry. The telecom industry has long-term cost-of-service rates underlying the basic services provided by, say, Bell or B.C. Tel. When they wanted to introduce new services that were driven by customer needs, they would bring that in as a separate, independent application with the revenues associated there. If the utilities are going to operate under, let's say, PBR with an earnings sharing mechanism, then there's excess revenues that can be shared. I mean there's ways around it. 424 What we, traditionally, in this Ontario market have, is everything has to go into one pot, into one hearing, once a year or whatever the frequency is, rather than maybe separating specific services out as something to be done offline. And for those who don't know, the CRTC, at least in the '80s, was getting close to over 1,000 applications a year from the telecom companies and most of them -- none of them were main rate cases, all of them were new service opportunities. A lot of them from new service opportunities and introductions through that mechanism. 425 MR. HAUSMANN: Thank you. Anybody else? Questions, comments? Mr. Scully. 426 MR. SCULLY: Peter Scully for the Federation of Northern Ontario Municipalities and the cities of Greater Sudbury and Timmins. 427 The first question is for Tom. In the last few years I've grown to hate PGVA clauses and their operation because just when I think I know how the numbers are going to work in a case, somebody runs in and says, Oh yeah, that's before the PGVA, now we have to accommodate that. So my ears perked right up when you said smart meters could perhaps eliminate the need for PGVA. I didn't follow that through. I couldn't see how that could be done. Could you expand on that? 428 MR. ADAMS: Sure. The basic reason we've got PGVA is to cover forecast versus actual variance. If we had -- and part of that variance arises because of the timing delay in the utility receiving information about what customers actually use. And then, of course, because of these timing delays, although there may be fluctuating costs to the utility over that time period, they have to use estimation curves to allocate the actual incurred expenses incurred to the customers. With information technology, you can keep track of which customers use what volumes at specific periods of time, and then the forecast versus actual variances start to disappear. 429 So as the time resolution of the metering improves, then the forecast versus actual variance can virtually evaporate. That's the concept. 430 Just to -- if maybe I haven't expressed it clearly enough. But imagine a utility that was only reading customer meters annually but incurring the expenses over the period for delivering the commodity. Obviously, the lack of resolution would result in even greater estimation errors. 431 MS. HARE: Marika Hare speaking, and although that would eliminate the PGVA, as we heard last week, we do not believe that buying on the spot market is in the customer's interest. And so although that mechanism would eliminate the PGVA, this is not, in our minds, how to solve that problem. 432 MR. HAUSMANN: Mr. Scully, more questions? 433 MR. SCULLY: The second question I have, and this is sort of up for grabs generally, is having everybody always alert to lower cost of capital very much appeals to me. I spent years in the utility business, and I could never understand why you can't finance a nice solid gas utility at about an 80 or 90 percent debt level. That still escapes me and nobody else seems to agree with me. But one thing I keep thinking about is, somehow or other, it may be possible to deal with all those disgruntled customers out there who distrust their gas utility if they were owners. And selling them equity always gets sort of tricky, but what about selling them some nice, firm, guaranteed debt? Has that idea ever kicked around any utility hauls? 434 MR. CAMPBELL: Rick Campbell. 435 I can't comment on that specifically. But I can't help but make the observation that, for a lot of years when I worked at a place called Ontario Hydro, a utility with a 90 percent debt ratio and a utility that thought that was working pretty well, my goodness, there were a lot of people who thought that did not work well, to put that amount of debt on the street and finance it annually through rates. 436 MR. SCULLY: And for the utilities, thinking about this and how it might work, am I correct that if we want to talk to anybody about how you might raise cheaper debt, the addressees would be Enbridge Pipelines and Duke Energy; is that -- I don't know how -- in the intercorporate relationships, where the financing decisions are now made. Can you help me with that? 437 MS. HARE: Marika Hare speaking. In the case of Enbridge, Enbridge Gas Distribution raises its own debt. It is done through Enbridge Inc. 438 MR. SCULLY: So you've got a fully functioning in-house, Toronto-based financing team? 439 MS. HARE: No. The treasury department is Enbridge Inc., and it will raise debt both on its own behalf and on behalf of Enbridge Gas Distribution. 440 MR. SCULLY: Okay. 441 MR. PACKER: Mike Packer, Union Gas. 442 Peter, if you have questions, I guess, about how we raise debt or how that -- any changes of how we raise debt and it impacts rates, I guess it's open to you to ask those questions in the context of a rate case. We're always willing to hear submissions and understand where it is you're coming from. 443 MR. SCULLY: No. I just think that this Board, when it's thinking about its recommendations, should have in its head who they would really be addressing their remarks to. I mean, I'm trying to cross-examine you or embarrass you about where the debt is raised or anything. I don't care. I just want to know. 444 MR. PACKER: I'm here representing Union Gas, and the remarks should be directed towards Union Gas. 445 MR. SCULLY: Okay. I'm addressing you as Union Gas. Remind me how that function is split between the existing Union Gas in Ontario and Duke Energy. 446 MR. PACKER: I'm not really in a position to be able to lay that all out for you today, Peter. 447 MR. SCULLY: Maybe that's something you could address in your final presentations. I don't know, maybe the Board is not interested. I am. 448 MS. HARE: Marika Hare. 449 I don't know if I answered you fully. The treasury department within Enbridge Inc. raises debt on behalf of Enbridge Gas Distribution. For that service, there is an amount that's allocated in the corporate cost allocation, in the case of Enbridge Gas Distribution, paid to Enbridge Inc. for the services, such as treasury, investor relations. 450 MR. HAUSMANN: Any other questions? 451 MR. BETTS: If you are looking for comments from the Board, I don't think the Board necessarily expects an answer to that. But I'll leave it to the panelists if they choose to answer it or are able to answer it. 452 MR. SCULLY: Thank you. 453 MR. HAUSMANN: Mr. Scully. We have -- yeah, another question coming up. 454 MR. ROSS: Murray Ross from TransCanada PipeLines. 455 This is following up on some of the other questions. I was just trying to understand, assuming we are in the middle of a multiyear cost of service or PBR and the customers and -- the utilities were to deem it necessary that there should be a new service provided or a new rate class, how would you go about getting approval from the Board to offer that service or class? 456 MR. PACKER: Mike Packer, Union Gas. We keep going back to our trial PBR plan, but it's fresh in my mind so I'll continue to do that. That issue was tackled in the context of the Board approving our trial PBR plan, and essentially, I think, the process that was laid out was that if, in consultation with customers, it was determined that a new service was required, we'd bring that forward in the customer review process, which we would envision at the time, and then the Board could approve it. 457 MS. HARE: Marika Hare. 458 We don't have a specific PBR plan on the table right now, but we have been looking at PBR for the last number of years and have floated some plans by intervenors. And we always envisioned, even if it's a multiyear plan, that there would have to be a discussion with intervenors so that we could, for example, discuss financial results in the year before and introduce concepts of new rate classes; changes to cost allocation might arise during a five-year period. There would be a number of issues that we always had envisioned would be discussed with intervenors. And I would say that a new rate class, a new rate service, would be done in that context, and it might mean an application to the Board. But, again, this is also very doable within a long-year plan. 459 MR. PACKER: Mike Packer. 460 If I could just add a couple more comments on it from Union Gas's perspective. I just note that, even though we're not currently in a multiyear pricing situation, we have had one filing this summer where we filed a response to a directive dealing with a rate class for high-volume users, and we have a directive outstanding that we will respond to by the end of the year dealing with the transportation rate to third-party storage developers. So even in the context of not having a multiyear plan in place, there is a requirement or a need sometimes to make filings with respect to specific rate issues, and we have and will make those to the Board when it's appropriate. 461 MR. ROSS: I think that's fine. I think -- I would hope that we would all agree that it wouldn't make sense to wait five years until the next PBR, multiyear cost of service is up to tackle a new rate design or new services. 462 MR. HAUSMANN: Thank you, Mr. Ross. 463 Any other comments, questions? Mr. Betts? 464 MR. BETTS: Thank you. It's Bob Betts here. If nobody else has one, I do have a couple of questions. 465 First of all, I just wanted to say, I appreciated Tom's answer to my questions earlier, because it highlighted for me something that I think I was aware of before, and that was the level of frustration and disappointment when particularly, and I'm speaking to the Enbridge PBR, or coming out of the Enbridge PBR, the amount of disappointment or frustration I noted from all parties. And I sensed that equally from the utility as I did from the intervenors. 466 I'm not sure, and Mr. Packer can think about the answer in the context of Union coming out of their plan as well, but I wondered if I asked each of you what things could have been done differently to reduce the resultant disappointment and frustration that was apparent to the Board? I think everybody wants the other one to answer first. 467 MR. PACKER: We're just collecting our thoughts. 468 MR. ADAMS: Having spoken too quickly once before, maybe I'll let the utility speak first. 469 MR. PACKER: I guess from my perspective - it's Mike Packer for Union Gas - when we proposed our initial PBR structure, we believed that we were moving into a different regulatory arena where parties would be less concerned about cost and more concerned about prices. As it turned out, I think we've heard a lot of comments that would suggest that parties are still very much focused on cost, and wanting to understand in detail the utility's cost structure. 470 So in that context, I think there's been a clear understanding up front about what it is the Board's trying to achieve, and why. And how the regulatory structure that's put in place actually achieves those things may help everybody understand why it is we're moving in the direction we are. 471 In our specific situation, I think it's fair to say that most people can't identify the benefits that came out of our plan, and from the company's perspective, that's partly related to the fact that we had a fairly high X factor. The customer review process was still adversarial and time-consuming. We still had the remnants of cost of service in terms of having to produce revenue-to-cost ratios annually. And maintaining S&T deferral accounts that were, in our view, a remnant of cost-of-service regulation. Again, a different sharing structure around them, just complicated the whole process. 472 For some reason, parties couldn't identify -- external parties couldn't identify the benefits, even though there were rate reductions two of the three years. There seemed to be an expectation that where customers were going to get the benefit was in terms of earnings sharing, and it wasn't until the last year that there was any earnings sharing, which is predominantly related to weather anyway. So in my view, it's really understanding why we're operating under the regulatory structure we are and what people should expect out of the regulatory structure as the plan unfolds. 473 MS. HARE: Marika Hare for Enbridge Gas Distribution. 474 Before I answer the question though, I do want to make a comment, because although there was -- certainly your perception that there was a lot of frustration on everybody's part is true, but I don't want people to read into that that we believe that the targeted PBR was not a success. It was a success in many ways. 475 First of all, there was definitely a change in the utility management in terms of how it looked at its utility business. There was a new focus on key operational indicators. And utilities are known to be risk averse, and that probably is true, but there was more of an entrepreneurial culture that was introduced because of targeted PBR. So these are all successes of PBR. 476 Financially, I looked at the results from the last 13 years to see, did we do better financially than when under cost-of-service, and the answer is not really. One of those three years was our best year, but not by much, and we had two years, one which was towards the bottom of the range and one was mediocre. So financially, you can't really say that it was a success, but neither was it a failure. 477 But in terms of what we could have done differently, one was clear expectations as to what would be allowed during that period or not. Second, was a greater disclosure and transparency. And one thing that I regret is the intervenors had asked during the course of those through years to see what our actual O&M numbers were, and our company position was, No, we don't have to disclose that because you don't need to know it. It's set by formula. And that, in fact, was true, but it wasn't very smart. Because at the end of the day, everything was disclosed and there was really no benefit to not disclosing those numbers as we go. So that's something that I think the company learned. 478 Lastly, in terms of the plan itself, I've mentioned several times, it did not have earnings sharing. The benefits to the ratepayers was in the form of that productivity factor that did have a stretch factor and there was the promise of rebasing at the end of the three-year term. And I think Patrick has talked at length about at the end of three years, how do you prove that you are actually better off than you would have been had you not started this, because nothing is the same. Had we had earnings sharing, I think intervenors would have felt that they were actually getting something for their customer groups all the way through. So in terms of the plan design, that's the one that, in hindsight, I think might have improved the relationship and the whole regulatory atmosphere that we had. 479 MR. ADAMS: I'm not sure how to respond to the atmosphere comment that Marika had -- Tom Adams -- at the end of her comments. It may well be correct. I must say that I think that Energy Probe is a bit of an outlier amongst of the consumer groups in the sense that we're much less keen on earnings sharing -- and we're perhaps -- perhaps more than happy to have an experience during a PBR period of utilities earning, perhaps, even well beyond the ordinarily allowed ROE. But that -- that's us in contrast to perhaps the views of some others. 480 So I'm not sure that -- well, for PBR to work, if we think that there are significant efficiencies out there, the time horizon has to be long enough so they can capture them and there has to be a way for the utility management to have a prospect for capturing something, otherwise it won't take the risk of attempting it. I think that needs to be brought into the question for the design of PBR in the future. 481 But in hindsight, I think that the comments that the utilities just spoke to with regard to transparency and disclosure are very well taken points. I think that would be a big difference on behalf of the intervenor community at large. I will leave it for others to speak their own mind, but my sense is it would have really been important. 482 MR. BETTS: I know this might be a little bit outside of our normal process, but I found the Board can do these things when they want to, so I'm going to take advantage of that. And I know that there are other intervenor groups that are represented here that were part of the process, and I wonder if any other intervenor groups would like to answer that same question: What could have been done differently in the processes to improve the results and reduce the level of frustration and disappointment that I sensed, anyway? Any other comments. 483 MR. FOURNIER: I'll jump in. Peter Fournier from IGUA. 484 Certainly, in the case of the Enbridge targeted PBR, our disappointment was when Enbridge, entirely in their good wisdom, found a different business model that they could move to that had scope, at least, to generate larger profits for the company and for its parent. There's nothing wrong with that, that's the whole idea of giving the company the freedom to find new solutions. But in our view, the outsourcing that Enbridge did changed the dynamics of the PBR scheme that we had agreed to. IGUA, CAC and I think VECC were with us also, sought to then have a re-opening, and the OEB, for its own good reasons, said no. And I think that was, with hindsight, a very disappointing result. 485 I can give you an example. I was going to use this tomorrow. Take a utility that has -- everybody agrees the revenue requirement is a thousand dollars. And a component of that thousand dollars, let's say, is $30 for corporate services provided by the parent. There's a revenue sharing, there is an incentive agreement for the revenue sharing of say 50/50. The company in its first year takes some steps and does indeed achieve some savings, let's say, of $20. So under the sharing mechanism, it would share that 50/50, $10 to the ratepayers and $10 for the shareholder. But instead of doing that, the parent increases the cost of its corporate services to $50 so there is no savings and the corporate parent then captures all of that $20 savings to itself. 486 If you don't have a scope for re-opening, then that kind of a situation can occur. So certainly if IGUA goes into negotiation with either Enbridge Gas Distribution or Union Gas, we will look to try and put in place certain checks and balances or re-openers. Where I think that may fail is that the level of checks and balances that we may think we now require, given our experience of what's gone on, would make that kind of an agreement or settlement unacceptable to the utility, because the utility wants to have that scope to use their good imagination and find new ways. 487 So that was our problem with what happened in the Enbridge case. I think they were entirely operating correctly when they made these innovative changes, but at the same time, I think we had legitimate case to say, Hey, hold on, this has changed the dynamics or the parameters. The OEB didn't allow for a re-opening and I think that was the disappointment we had with the first Enbridge PBR. 488 MR. HAUSMANN: Thank you. Mr. Shepherd. 489 MR. SHEPHERD: From Schools point of view, we think there were two main problems with the Enbridge PBR. 490 MR. BETTS: If I could and I appreciate that everyone will try to do this, but we'll be as non-specific as possible and make them kind of generic responses to that. 491 MR. SHEPHERD: I was going to add, and probably applicable to the Union PBR as well. There appears to us to have been two problems. On the utilities side, the utilities did not embrace the fish bowl concept that Tom Adams has referred to, and thus were very limited in their disclosure. And this was not just, as Ms. Hare said, along the way. At the beginning, when the utilities had plans to do things or were thinking about options to substantially change how they ran their utility, it would have been a good idea for them to have a frank and open discussion with their customers about those things so that they didn't come as a surprise. That was the biggest, I think, single problem creating distrust. 492 Then there was not enough disclosure along the way and then there was a fight about disclosure at the end as well. And that whole thing -- it doesn't matter what the legalities are, at the end of the day it's about whether you trust each other and whether you think you can work together, and that problem, the lack of disclosure, created or exacerbated the distrust. 493 On the ratepayers's side, the ratepayers were too tied, in both cases, to the costs of the utility and weren't willing to let the utility make some extra money by taking some extra risks. The ratepayers, and we think very strongly, missed the point: If your rates are driven down, that's a good thing. And they focused instead on how much the other guy made instead of worrying about how much they benefited, and that was a mistake on the ratepayers's part. 494 MR. HAUSMANN: Ms. DeMarco. 495 MS. DeMARCO: If I can comment on behalf of a number of the clients that we were acting for, largely in the marketing community, throughout the course of the evolution of PBR. First and foremost, I think many of the frustrations resulted from the expectations and objectives that were set out by the Board and its consultants. And I remember predominantly that there were three main objectives that were created for PBR. 496 The first was to address the information asymmetry problem. Significantly, there's always difference in the information possessed by the utility versus possessed by intervenors. PBR was seen to be the solution to that information asymmetry problem by just providing an economic incentive to get the same efficiency out or greater efficiency out of the utility without having to tackle, on a regular basis, the information asymmetry problem. 497 The second was that there was an expectation of administrative efficiency. This would be far more streamlined, it would take far less resources of the Board and it would take far less resources from the intervenors. They could trust that a surrogate for a market mechanism, and those were the terms used, surrogate for a market mechanism, would deliver the efficiency. 498 And third was the expectations upon rebasing. There was a significant expectation created both by the Board and by the utility in the original PBR applications that there would be significant efficiencies realized upon rebasing. 499 What happened in relation to those objectives was very different than what was anticipated would happen. In particular, the information asymmetry problem was exacerbated. There were real concerns about the voracity of the initial cost-of-service numbers going into the actual PBR plan, and that took the form of some very heated and antagonistic evidence during a motion following the first PBR plan. 500 There was a sense that instead of having the efficiency gains address the information asymmetry problem, outsourcing was used to, in fact, shield the subsequent information to ensure that there was not the same asymmetry, that there was still clear and transparent understanding of the numbers going into this. 501 In terms of administrative efficiency, we saw a plethora of applications and motions come forward in relation to the information that wasn't there. We saw attempts to obtain information and realize the same efficiency that we thought was promised. And this is interesting, because in relation to the questions about how do you address new services, we've heard that the telecoms have seen and entertained thousands of specific applications related to specific issues because they've got a five-year term. If it promises administrative efficiency, I think we need to look at that very carefully and realize where they're going. 502 And third, in relation to the ultimate test, the efficiency upon rebasing, I think it speaks directly to Mr. Hoey's comments about the new car. It's very hard to move a regulated utility and regulated public from a concept where they measure the deal they're getting in terms of cost-of-service to change the thinking in an attempt to measure the deal they're getting in terms of something else. So certainly, I think many of the frustrations that were experienced by the competitive community, that is, affected by rates and their customers revolve around those three objectives and how they played out in the context of PBR. 503 MR. ADAMS: Tom Adams. I wonder if I could add one small thought to the previous discussions stimulated by some of the comments of the others. 504 One thing to appreciate about the initiation for the TPBR model was it was all tied up at the tail end of a long, very difficult period of CIS and previously SIM development in-house, and incentive regulation became a vehicle for completing that process. That's, in fact, actually what happened as a business reality within Enbridge, but lead up to PBR left-unfinished business dumped into a new regulatory model, and that may be one of the things that complicated the disposition or -- the eventual outcome from that event, because CIS was central to the restructuring that happened during PBR. 505 MR. HAUSMANN: Anybody else? 506 MR. BETTS: Let me ask one more question, then, for clarification. This word has been used by virtually everybody at least once, and that's rebasing. And I'm going to ask all of you what you think is included in rebasing. Who would like to start? 507 MR. PACKER: It's Mike Packer for Union Gas. 508 When I hear the term "rebasing", what I think of is a process where you look again at what the utility's revenue cost structure is at a point in time and that's how you set rates. So any productivity improvements that have been achieved up to that point get given back to ratepayers. The other aspect to it that I read into it, and maybe this is because of my previous experience on rate design and cost allocation, but rebasing is not just at the company level, but it could also be at the rate-class level, where rates are adjusted to get them back closer to cost. That's what I think of rebasing. 509 MS. HARE: I'd agree. 510 MR. ADAMS: I have a little child -- kind of borrowed that understanding from that model, from the RPI minus X and then rebasing model. And there my emphasis is not on the cost structure but the achieved return on a normalized basis. So that any overearnings that were hopefully incented during the period of PBR are clawed back. That's what I mean by rebasing. 511 MR. BETTS: You're saying that they would be clawed back. 512 MR. ADAMS: Clawed back at the conclusion of the term. As the PBR term expires, the rebasing happens at that point, not in the mid-point. 513 MR. BETTS: But let me ask you this to make sure I understand that, any earnings, any earning benefit that was derived by the shareholder during that, let's say, three-year period, would you be expecting them to return years 1 and 2 to the ratepayers? 514 MR. ADAMS: No, no. That was the cheese to get them to go forward with the efficiency gains. 515 MR. BETTS: Thank you. Those are all my questions. 516 MR. HAUSMANN: Any other questions from the Board or Staff? Any final comments from participants? 517 Well, in that case, it seems we've come to the end of our agenda for today. We will reconvene tomorrow morning at 9:00 a.m. with the last day of the rates regulation agenda Forum. 518 Mr. Betts, do you have any final comments? 519 MR. BETTS: Just, once again, thank you. That was an excellent discussion. We appreciate everyone's openness and assistance with that, and it will help us going forward and all of us develop better plans in the future. We look forward to seeing everybody tomorrow morning at 9:00. It looks like another half day. We do have five members in that first panel, so it could be a long one with you once again. Thank you all and we'll see you tomorrow morning. 520 --- Whereupon the hearing adjourned at 12:42 p.m.