Rep: OEB Doc: 1388W Rev: 0 ONTARIO ENERGY BOARD Volume: 15 13 JULY 2004 BEFORE: R. BETTS PRESIDING MEMBER P. NOWINA MEMBER P. SOMMERVILLE MEMBER 1 RP-2003-0203 2 IN THE MATTER OF a hearing held on Tuesday, 13 July 2004, in Toronto, Ontario; IN THE MATTER OF the Ontario Energy Board Act, 1998, S.O. 1998, c.15 (Schedule B); AND IN THE MATTER OF an Application by Enbridge Gas Distribution Inc. for an Order or Orders approving or fixing just and reasonable rates and other charges for the sale, distribution, transmission and storage of gas commencing October 1, 2004. 3 RP-2003-0203 4 13 JULY 2004 5 HEARING HELD AT TORONTO, ONTARIO 6 APPEARANCES 7 JENNIFER LEA Board Counsel COLIN SCHUCH Board Staff JAMES WIGHTMAN Board Staff FRED CASS Enbridge Gas Distribution Inc. DENNIS O'LEARY Enbridge Gas Distribution Inc. TOM LADANYI Enbridge Gas Distribution Inc. TANIA PERSAD Enbridge Gas Distribution Inc. MICHAEL CADOTTE Union Gas Limited PATRICIA JACKSON Union Gas Limited JIM LAFORET Union Gas Limited ROBERT WARREN CAC & CCC JULIE GIRVAN CAC & CCC MICHAEL JANIGAN VECC ROGER HIGGIN VECC PETER THOMPSON IGUA JAY SHEPHERD School Energy Coalition DAVID POCH Green Energy Coalition MELANIE AITKEN Direct Energy Marketing Limited ELISABETH DeMARCO CEED, OESC, Superior Energy Management, TransAlta Energy Corporation MALCOLM ROWAN CME CAROL STREET CME MURRAY KLIPPENSTEIN Pollution Probe JACK GIBBONS Pollution Probe BRIAN DINGWALL Energy Probe THOMAS ADAMS Energy Probe VALERIE YOUNG OAPPA, Casco, Maple Lodge Farms, Markham District Energy MURRAY ROSS TransCanada PipeLines 8 TABLE OF CONTENTS 9 SUBMISSIONS BY MR. DINGWALL: [34] SUBMISSIONS BY MR. JANIGAN: [316] PROCEDURAL MATTERS: [440] CONTINUED SUBMISSIONS BY MR. JANIGAN: [466] SUBMISSIONS BY MS. AITKEN: [677] SUBMISSIONS BY MS. JACKSON: [838] 10 EXHIBITS 11 EXHIBIT NO. K.15.1: DOCUMENT ENTITLED "CORRECTION TO ORAL TESTIMONY" DATED JULY 7, 2004 [27] EXHIBIT NO. K.15.2: ENERGY PROBE FINAL ARGUMENT DOCUMENT COMPENDIUM [38] EXHIBIT NO. K.15.3: ARGUMENT OF THE VULNERABLE ENERGY CONSUMERS COALITION, JULY 14TH, 2004, BOOK OF REFERENCES [321] EXHIBIT NO. K.15.4: DOCUMENT ENTITLED "APPLICATION OF CONNECTICUT NATURAL GAS CORPORATION FOR APPROVAL OF A CHANGE IN FISCAL YEAR," DATED JANUARY 31, 2001 [639] EXHIBIT NO. K.15.5: COMPENDIUM OF DIRECT ENERGY MARKETING LIMITED [684] 12 UNDERTAKINGS 13 14 --- Upon commencing at 9:39 a.m. 15 MR. BETTS: Please be seated. 16 Good morning, everybody. Today is day 14 of the hearing of application RP-2003-0203. Another day for -- 17 MR. SCHUCH: Mr. Chair, I think it's day 15. 18 MR. BETTS: Day 15. Thank you for the correction. I usually keep track of those day numbers very well, but... 19 Anyway, we are now, today, as we did yesterday, receiving oral arguments from intervenors, and it's my understanding that our schedule today will be Mr. Dingwall, Mr. Janigan, Ms. Aitken, Ms. DeMarco, and Ms. Jackson from Union. Before we begin that, there's one item I just wanted to tidy up. 20 Yesterday I received a document from the applicant entitled, "Correction to Oral Testimony." And I don't know how that fits into the record, whether it should have an exhibit number or -- perhaps I could ask Mr. Cass what his recommendation is. 21 MR. CASS: We weren't sure either, Mr. Chair, and that's why it does not currently have an exhibit number on it. Since you have brought it up, it might perhaps be appropriate to give it an exhibit number now. 22 MR. BETTS: Certainly, I think we should have a way of referring to it. So, Mr. Schuch, let's do that. Let's establish an exhibit number for this document. 23 MR. SCHUCH: Certainly, Mr. Chair. That's assigned Exhibit K.15.1. And I don't have a title for the document as I don't have it in front of me. Perhaps Mr. Cass can... 24 MR. CASS: I don't have it in front of me, but it did have a title on it, Mr. Chair. 25 MR. BETTS: I have it in front of me. And the title is "Correction to Oral Testimony." And it's dated July 7th, 2004. It's a quarter-page with several pages of attachments. 26 MR. SCHUCH: Thank you. 27 EXHIBIT NO. K.15.1: DOCUMENT ENTITLED "CORRECTION TO ORAL TESTIMONY" DATED JULY 7, 2004 28 MR. BETTS: Are there any other preliminary matters that the Panel should deal with? 29 If not, has there been any discussion amongst intervenors as to their preference on order of submission? 30 MR. DINGWALL: My understanding, sir, is that I'm to go first, followed by Mr. Janigan, followed by Ms. Aitken, followed by Ms. DeMarco, and followed by Ms. Jackson. 31 MR. BETTS: Well, that coincidentally matches our schedule as well. So let's proceed on that basis. And Mr. Dingwall, are you in a position to proceed at this point? 32 MR. DINGWALL: I am, sir. 33 MR. BETTS: Please do. 34 SUBMISSIONS BY MR. DINGWALL: 35 MR. DINGWALL: Well, let me start off by indicating that Mr. Adams, the Executive Director of the Energy Probe Research Foundation, is present and is currently distributing not propaganda, but what we intend on using as a guide for the final argument of Energy Probe. 36 It's our intention to address final argument in order of the issues as they appear on the issues list. It may not lead for a finish of sound and fury, but it might make a bit more sense and be somewhat more clear for the reading of the record. 37 MR. SCHUCH: Mr. Chair, perhaps we should now assign an exhibit number to this document. And that would be Exhibit K.15.2, Energy Probe final argument document compendium. 38 EXHIBIT NO. K.15.2: ENERGY PROBE FINAL ARGUMENT DOCUMENT COMPENDIUM 39 MR. BETTS: Thank you. I noticed mine was already marked as 15.1, so if everyone can change the number to 15.2, that would be great. Thank you. 40 Mr. Dingwall, please proceed. 41 MR. DINGWALL: Thank you. 42 So, then, in following the issues list, the first issue to be addressed is the transactional services proposed by the company. What is somewhat different than traditional transactional services is that for the test year the company is proposing to continue the performance of transactional services through Enbridge Gas Services, including, together with excess utility assets, a rebundling of those assets with commodity purchased by Enbridge Gas Services to create new products to market to end-users. 43 This is a significant deviation from the previous approved platforms of transactional services. What's somewhat surprising is that the company did not disclose until somewhat late in this proceeding, in stakeholder consultations last fall, that there was even the spectre of a previous pre-approval inclusion of commodity together with transactional services. 44 Traditionally, the ethos behind transactional services is that when the utility, through the performance of its regulated function, has assets which it does not need, such as excess transportation, excess storage, et cetera, that the utility should then maximize the value of those assets to ratepayers for whom those assets were acquired, by the sale of those assets to third parties in the marketplace. 45 That puts the utility being in the awkward position of having a significant knowledge of system operations, system integrity, who needs what, who doesn't need what, and having to balance that with its obligations as the regulated monopoly to be neutral in the marketplace. 46 Traditionally, the nature of the transactional services business was such that it was habitually devoid of regulatory scrutiny. In the performance of these transactions there has never been any ability for the regulator to audit what the amounts of the monies received for them were, who the parties might have been, the terms under which the dispositions may have occurred, and what books and records were kept in respect of these transactions. Traditionally, the recording of information with respect to these transactions is done in the rate case. It's a number on a piece of paper that is based on solely the sale of excess assets. It's left to trust to understand that the utility, in the performance of its regulated function, used these assets in a neutral way, and in a way that would non-controversially not incur any other costs. 47 When you're selling something, you don't have to buy anything; you don't have too many blendings of costs in order to muddy the paper trail. With a bundling of commodity together with transactional services, that creates a completely different spectre in the marketplace. It creates a situation where Enbridge Gas Services has now, for the past year, added commodity together with the excess assets. The evidence has indicated that this has created a significant and material change to the risk profile associated with the performance of transactional services to the point where Enbridge Gas Services has, of necessity, required parental guarantees in excess of $100 million in order to perform these functions. 48 The company's proposal is not only that these services continue, but that the notional -- a word which we heard a lot of in this particular proceeding -- the notional credit costs associated with the provision of parental guarantees be paid for by ratepayers as part of the service fees associated with transactional services. 49 The alternative that the company has put forward is that the transactional services as they relate to commodity be conducted in Enbridge Gas Distribution's name, which would then leave the regulated entity and its asset base and all the various related capital requirements that relate to how it operates its monopoly open to that risk. 50 What's curious about the proposal is that there is no suggestion that, prior to any sharing, a notional cost associated with whatever credit requirements Enbridge Gas Distribution might have of a similar variety to what Enbridge Inc. was posited to have had, were suggested to be deducted. It would seem to me that if the proposal were to have an element of clarity, that the company would have proposed that, if they view the opportunity loss of a credit facility as being somewhere in the area of a $2 million cost, that that would be proposed as another amount to come off the top of transactional services, in this case, to the credit of the ratepayers, prior to any sharing. I was very curious that that wasn't suggested. It seems somewhat asymmetrical. 51 In addition to the proposal having the propensity to expose the regulated entity to additional credit risk of a significant magnitude, there's also the effect that the increased scope of transactional services has on the competitive commodity marketplace. For utility assets to be bundled by a utility affiliate with non-regulated assets, in an entity which is not open to audit, raises a number of questions as to how, under any circumstances, there could ever be regulatory clarity of the manner in which the regulated assets were being used. 52 It also raises a question of how, with any degree of clarity, there could be any prevention, let alone tracking, of whether the commodity that might be bundled together with the transactional services might be coming from a related party or an affiliated party, or as an adjunct of some other transaction which might then flow profits out of the bundled transaction into a third party's hands and outside the purview of transactional services revenue, as they would flow to ratepayers. 53 It's for these reasons that Energy Probe believes it's inappropriate for the company to continue with the bundling of commodity in respect of the transactional services that it has traditionally performed. It is also Energy Probe's view that the historical, for the past year, bundling of commodity transactional services was not only significantly inappropriate, but also we question the motives as to why the company would have entered into such a clearly controversial field without, firstly, giving information to stakeholders or the regulator about its intended scope. That's a theme that's going to recur within the space of this argument. 54 My next -- I'm going to pause, then, at the end of each section to see whether the Board might have questions on the section. I'll also invite whatever questions might come about at the Board's volition, should you wish to interrupt at any time. 55 MR. BETTS: Thank you, Mr. Dingwall. Please proceed. 56 MR. DINGWALL: The next matter I'd like to speak to is the proposed Union Gas storage contract, which is subsumed under issue 5.1. 57 While the proposed volume of storage is representative of the minority of what the system needs are, I believe roughly around 20 percent, from the evidence, the fact that the company is seeking to enter into a new agreement when there is a pre-existing agreement which has another two years to run seems somewhat suspect, given the timing of the presentation of the agreement in context of the company's previously announced plans to consider the separation of storage on a number of occasions, as well as the upcoming Natural Gas Policy Forum, which is slated to address whether or not storage might be competitive. 58 We think that a long-term contract of that nature, while historically in line with previous utility practices, given that it's an early renewal, it is inappropriate with the regulatory landscape that we're proceeding towards. 59 It raises the potential that, in the event that storage does become competitive, that there may be a significant stranding of the costs associated with this agreement, either with ratepayers or as a matter of unbundling in the future. If the storage market were to follow the market as it's progressed to date on an incomplete unbundling with respect to transportation, then it's conceivable that the storage market might look something like a vertical sliced market, though in storage the slice would not be on a piece of pipe basis. It would be on a time-of-contract basis. Meaning that the various storage contracts that the utility might have might be unbundled to agents to market on a basis of what the particular slices of system contracting might look like. This has been a practice that's been followed in a number of jurisdictions, notably Ohio, and which has created significant interperiod variations in the price of storage versus the value of storage, in that old contracts that the utility may have made, which fall in and out of the money, tend to not match when they're assigned the value of the storage contracts that might be available in the marketplace. 60 One thing I must say is that the company in the negotiation of this contract was mindful of the fact that this contract was ostensibly replacing a pre-existing contract which, for the test year and the subsequent year, had significantly lower costs associated with it. And the company has been prudent in leaving the option open to the Board of choosing to reject the cost consequences of the new contract, in which case the default would be to the cost consequences under the old contract, which for the test year would provide a significant saving. 61 It's our submission with respect to the Union Gas storage contract that the Board should not approve cost consequences associated with this contract, which would have, then, a necessary result that the company would default and ratepayers would receive the benefits of the costs under the pre-existing storage contract. 62 That completes my submissions with respect to that topic. 63 MR. BETTS: Thank you, Mr. Dingwall. Please proceed. 64 MR. DINGWALL: We then move on to issue 5.2, which is risk management. 65 The applicant had retained RiskAdvisory Inc. to review its risk-management program as a result of the fiscal 2003 ADR process. RiskAdvisory made certain recommendations of support which the company is proposing to adopt and which it requests the Board to approve. The significant changes to its program are to remove the 10 percent of volumes that can be hedged at any one time, and permit the gas supply risk-management committee the flexibility to hedge large percentages... 66 MR. BETTS: Mr. Dingwall, for some reason the volume of your voice declined, and I didn't see you doing anything different. So perhaps if you just try a little extra hard to direct your voice into that mic, we'll proceed. 67 MR. DINGWALL: My apologies, sir. I'll begin -- I'll restate a number of the things in order that they might clarify the record. 68 The significant changes to its program are to remove the 10 percent volumes that can be hedged at any one time and permit the gas-supply risk-management committee the flexibility to hedge larger percentages; and, secondly, to put in place a rolling 12-month hedging program, because the current program allows EGD to hedge only within the fiscal year. 69 It's Energy Probe's position that there are major policy issues to be dealt with before these changes should be implemented. Those policy issues should be considered in the Natural Gas Forum and not in a rate case. As a matter of timing, it appears to be an inappropriate signal for the Board to approve major changes to the applicant's risk-management program when the debate in the Natural Gas Forum is imminent. 70 As part of the discussions in respect of this portion of the evidence, the reference was made to a survey back in 1996 that established the original -- the original risk tolerance level of a $35 change per customer. As a result of Undertaking J.2.4, which is at tab 1 of Energy Probe's materials, that study was produced. And what we've included for the purposes of brevity is simply the introduction and the executive summary of that study. 71 One of the interesting things that I read when looking at that study subsequent to the cross-examination of the panel was that this particular study was intended at the time on addressing customer awareness of the direct purchase alternatives as part of its canvassing of the need for risk management at the time. 72 And then in reading the case decision around the case in which the study was presented, which would be EBRO-492, I noted that this was not the only study performed at the time. There was another study undertaken by marketers which sought to put forward the need for a fixed-price commodity service through the utility. At the time, the Ontario gas marketplace was in its infancy. There was something called the buy/sell mechanism in place. Utility customers paid their rate; the rates were set through orders of the Board; there was a purchased gas variance account - many of the mechanisms that we see today. 73 However, the competitive marketplace at the time was in its infancy. At that time, the only option that the direct-purchase community had was what was called the buy/sell, where the marketers would buy the natural gas at whatever price they could get it for, sell it back to the company, who would pay the marketers based on a reference price; and what the customer saw on their bill every day was the regulated rate. So the margin for the marketer would have been based around whatever saving they could make on what they bought gas for versus what the company bought gas for. The saving to the customer was based on a rather imperfect rebating mechanism. 74 As a result of the decision in that particular case in which the study referenced on the risk-management side was produced, the Board approved something called Agency Billing and Collection Service, which then enabled agents, brokers and marketers, or ABMs, as they were then known, to provide fixed-price for fixed-term commodity service which would then be billed to customers under the fixed-price basis. 75 It took some time for that decision to implement, but the basis for the assumptions around risk at that time were that the competitive market was not fully developed. And the fact that the study itself was contentious and led to a flurry of other studies in a contested proceeding in which the result was to allow the marketing community to implement a fixed-price service offering in response to the company's variable regulated rate; the result of that being that this fixed-price offering now came into place really shows that at the time the tolerance of risk was interdependent on the operation of the competitive market and in need of understanding what the relationship would be between the regulated offering and the competitive market. 76 Now, we note that, as part of the relief that the company is seeking, they're seeking the ability to undertake a customer survey and they've described it as being along similar lines as the survey performed in 1996 in order to gain a full understanding of the risk tolerance of individual ratepayers for the purpose of understanding what the limitations of the risk-management program might be going forward. 77 It seems fairly clear, in our minds, that there's a significant interdependence between the question of risk management tied up with the operation of the competitive market, and, given the Board's communicated mandates about regulatory initiatives coming up for the next year, also tied very closely with the operation of the process that's related to understanding what the future and nature of system-gas supply, that being utility supply, for residential customers might be. 78 And it's on that basis that we don't believe it would be appropriate for the company to undertake such a study at this point in time. Firstly, it would be undertaken, as they propose, in isolation. Secondly, it presupposes that there is a need for such a study to be performed in isolation in advance of the Natural Gas Forum, which would be addressing the future of system supply. And thirdly, a study of this nature, performed in isolation, would not have the value of understanding what all the stakeholder needs in the production of -- the solicitation of customers for that type of information might be, and might even have the potential of undermining the competitive market, depending on the size of the study and the questions that might be asked. 79 For those reasons, Energy Probe believes that the company's proposed changes to its risk-management policies should not be accepted in this process. 80 Those are my submissions with respect to risk management. 81 MS. NOWINA: Mr. Dingwall, I do have a question. I understand your point around the survey; that was quite clear. Around the other two issues, the 10 percent volume and the 12-month rolling year, and your rationale around that was that the gas forum is coming; that these are policy, if you like, issues, and that it should wait. 82 Can you expand a little bit more, because the company's already doing risk management, so this is a change in the risk management they're currently doing. Why do you see those as policy issues? 83 MR. DINGWALL: Well, let me address, first of all -- actually, let me have a quick conference with my client. 84 Let me first address the increase in the permissible amount of hedgable volumes hedged at any one given time, which was the 10 percent threshold. 85 It's my recollection that, on cross-examination, the witnesses indicated that the threshold above 10 percent was not any fixed number and it could go up to the amount of 100 percent of the hedgable volume, which is a formula that relates to a number of factors. And that the amount by which hedging could be increased was a matter of sole discretion on the part of the company. 86 It's our view that that's a significant expansion of the hedging program of a material nature that would have the effect of changing what system-gas supply looked like. It would provide a smoothing that would effectively be moving costs beyond the framework of current time periods. Part of that is also accomplished, or would be accomplished, through the rolling 12-month forecast. Under the current methodology associated with the clearing of gas costs, those gas costs are cleared on an annual basis. 87 What that does is that provides time period clarity, which is, again, going to be another common theme in this case, of what actual costs are. 88 One of the difficulties that came about in the marketplace upon the initiation of the ABC price was that there was a significant time lag in the time in which market signals matched utility prices, so there were times when there were offers in the marketplace - I can think of the summer of 1997 specifically - of five-year gas at 7.1 cents per unit, at a time when the utility price was, I think, 5.5 cents per unit. I was fortunate enough to sign up on one of those. In the subsequent year, the price went up significantly, and the year subsequent to that, the price went up to close to 30 cents for utility offering. 89 So if there's any potential for the actual gas costs to extent beyond the current time frames for clearing purposes, then it takes away from customers' abilities to make timely decisions relative to what they're paying the regulated rate -- for the regulated rate for the particular time period versus what they might obtain in a competitive marketplace. 90 MS. NOWINA: Thank you. That was very helpful. 91 MR. BETTS: Mr. Dingwall, I had a question on exactly the same topic, and you may have answered it in your answer to Ms. Nowina but I'd just like to expand it a little bit. 92 I'm not trying to plant words in your argument, but is your concern here -- did I understand your concern to be primarily that risk management may reduce the price signals in the marketplace and, perhaps as a mechanism of mitigating price volatility, may work as a harmful mechanism? Can you try to reply to this comment I just made? Does it fit anywhere in your argument? 93 MR. DINGWALL: Well, let me take a step back from that to consider that for one minute, if you don't mind. 94 In response to your question, the potential that risk management has is to dampen price signals in the marketplace. When you're smoothing out prices and dampening volatility, you're doing so at a cost. And the cost is usually a cost on top of what the actual prices would have been in the absence of risk management. So this has the potential to dampen the price signals that customers would have. 95 And taking it beyond an annual period, using a 12-month rolling methodology, puts you in the significantly worse position of not having costs tracked on a per-period basis, which is certainly what regulators need as an analogy in order to understand what's happening where, at what time - and I'll come back to that point on some of the other issues in this case - but also what customers need in order to understand how what they're paying relates to what they could be paying in the competitive market. 96 It's interesting that the witnesses made the point that it could be open for marketers to think about the consideration of variable contracts rather than fixed-term contracts as the utility, through risk management and other advocated positions they appear to be taking in other forums, that marketers might want to consider floating prices. 97 In response to an interrogatory from the Vulnerable Energy Consumers Coalition, Mr. Adams went through the mechanics associated with the provision of a floating-price service by a competitive marketer and how, with the various codes of conduct, it's not feasible for that option to be out there. 98 For a customer to agree to a price, there has to be an agreement in advance of that price, which means if the customer's price were to change, the customer would have to have advance notification of that change in price, which isn't feasible in order to gain the customer's consent to the change in price; and, given the dates on which prices must be changed before the utility for billing system purposes, would not be feasible to implement any form of floating price, even based on an index, because the prices are required to be posted well in advance of indexes for the relevant time period being available. 99 So with respect to the witness's suggesting - and I believe that was Mr. Simard - that marketers should consider that as an alternative, that alternative is not open. 100 MR. BETTS: Thank you, Mr. Dingwall. You may continue. 101 MR. DINGWALL: The next issue I'd like to speak to is issue 5.5, the phantom issue. 102 On Issues Day, the company sought to have this issue included on the issues list, citing a degree of you urgency for the company and its shareholder to receive guidance on the general appropriateness of potential transactions which might occur prior to the issuing of a decision in this case. 103 Specific mention was made of a large liquefied natural gas project in Quebec to which Enbridge Inc. was being asked to belly up to the bar on. At the time of Issues Day, the company was adamant about the need for guidance from the Board and appeared to be committing to providing whatever level of disclosure might be available at the time in order to achieve this guidance. 104 This is reflected in the passage from the transcript on March 25th, and I'll read this so there's no reference to -- or no need for the Board to turn at some point portion at paragraph 377. Mr. Betts asked the question: 105 "Let me just pursue that, then. You've indicated that you don't foresee the need to bring forward detailed information about contracts. What additional form of disclosure do you anticipate bringing forward?" 106 To which Mr. Cass responded: 107 "Well, again, Mr. Chair, I'm looking ahead here to things that I don't know for sure, so please don't take my comments on this as coming from someone who was able to predict with accuracy. What I would anticipate is the company would present evidence in areas where it is looking for direction. So at the time the evidence comes forward, the company would present the best evidence at that point in time about whatever Enbridge Inc.'s involvement might be, who the major proponents of the projects are, the extent to which the proponents are arm's length, those sorts of things, evidence about the issue that the company is seeking direction on." 108 Subsequent to Issues Day, a number of intervenors sought to strike the issue from the list, citing the lack of information that the company had put forward with respect to the issue. On the day the motion was heard, the company, rather surprisingly, withdrew any evidence which it had filed, which was on the eve of announcement that its shareholder had entered into a long-term arrangement with regard to investing in the referenced LNG facility. 109 At the time, the company explained the lack of evidence and intention that they would not provide anything further in the context of this proceeding as being due to the confinement of the evidentiary process and its limitations. The Board's response was to raise the concern that transactions which the company may have entered into respecting future commitments may have a weakened perception of prudence. 110 At paragraph 19 of the June 18th transcript -- or, I'm sorry, the June 18th decision on the motion, the Board says: 111 "We note that EGDI originally supported issue 5.5 on the basis that they needed guidance from the Board regarding future long-term contractual supply commitments. EGDI also recognized on several occasions the need to provide open and timely disclosure of their plans for change to avoid misunderstandings and a repetition of past feelings of mistrust and skepticism. "The Board Panel offered this opportunity and regrets that EGDI has not been able to take advantage of it. A preview of the long-term supply commitments which EGDI described on Issues Day may well have strengthened the evidence in a future proceeding that these commitments have been entered into prudently, and may have also provided additional comfort in entering into the agreements now. We are concerned that the company's about-face on the disclosure of its plans, especially in the broad form suggested by Mr. Cass on Issues Day and acknowledged by the Board in its decision on the motion on June 18th will have the effect of muddying future proceedings. Another concern is that the company is ignoring the Board's direction and guidance in this case in order to push the --" 112 I'm sorry -- the part which begins "we are concerned" would come at the end and subsequent to the quotation from the Board's motion and be my submissions. I just think I should clarify that for the record. 113 The Board made the suggestion to the company that they may not have a similar interpretation of the disclosure obligation in the following paragraph of the decision on the motion, which is paragraph 24. And now I'm back to the decision. "EGDI has implied that there is no evidence they have available to file that falls within the scope of issue 5.5. We are somewhat concerned with EGDI's apparent interpretation of issue 5.5. In its submissions to the Board, EGDI seemed to suggest that issue 5.5 requires detailed and concrete arrangements giving rise to commitments for long-term supply. That is not the interpretation which we hold, nor is it an interpretation which follows easily from a plain reading of the issue as it stands on the issues list. 114 "We note that it was our intent that the EGDI proposal to be submitted as evidence could be high-level and directional in nature. They could be, for example, business or strategic plans or approved proposals. The key test is whether or not it is the intent of the plans and likely outcome of them that commitments will be made before the next planned rate case." 115 An additional concern which arises out of this issue relates to customer communication. The Board's decision on the motion gave the company guidance on what it should be doing in the context of customer communications with stakeholders, especially in context of the competitive market. And this would begin at paragraph 29. "The question of customer communications is an important one, in light of the objective reflected in section 2, paragraph 1. In addition, in this proceeding, the Board is being asked to approve costs related to the development and dissemination of existing and new messages to EGDI's ratepayers. In the course of its submissions and in response to questions from the Board and other parties, EGDI indicated that it would be prepared to provide, in advance of distribution, refocused customer communications to the intervenors of record in the proceeding. While we have decided not to direct EGDI to do so, we regard such a courtesy to be prudent. We are particularly concerned that no customer communication be issued which would have the effect of creating confusion in the market, or which would use EGDI's market position as distributor to unreasonably skew the market toward system supply and away from the competitive environment as addressed by section 2, paragraph 1 of the Act. Should complaints be substantiated in this connection, whether from consumers or other market participants, the Board would consider appropriate action." 116 To date, there has been no communication from the company to stakeholders with regard to what plans the company may have in this regard. And this is somewhat concerning. 117 In context of this particular case, Energy Probe believes that the message which the Board has put forward in terms of cooperation and disclosure needs to be echoed in the decision in respect of this case, and in particular, it should extend to any intended customer survey that the company might consider outside of this process as it might relate to the Natural Gas Forum, given what has turned up under the auspices of the previous customer survey and how it extended into the categorization of competitive markets. 118 So, while under the heading of risk management we do not believe it appropriate at this time that the company even undertake that survey, if the Board does decide that that survey might be appropriate, for whatever reason, we would submit that that survey itself would have the significant potential to be used in some context to expand the scope of risk management through establishing potentially a new risk tolerance threshold and that that would have a material effect on the competitive marketplace. And while we don't think that risk management should be extended to the point the company is suggesting or that the survey should be done at all, in the event that the Board decides that the survey might be useful and should be done, we think that it falls clearly under the heading of something that, if it shouldn't be done, or if it should -- if the Board decides it should be done, it should be done with involvement of stakeholders. 119 Those are my submissions with respect to issue 5.5. Energy Probe did file evidence, which ostensibly spoke to this issue; however, Energy Probe did not call its panel, and in discussions with the company agreed that the company did not have the opportunity to test Energy Probe's evidence. Hence, the evidence would stand as untested. 120 Frankly, the evidence stayed on the record because we did not know if any evidence or any further disclosure from the company might come about, subsequent to the Board's decision on the motion. So, at this point, it's in kind of a limbo. 121 Are there any questions on this topic? 122 MR. BETTS: One question, Mr. Dingwall. Towards -- well, at the very end of that particular phase of your argument, you spoke about a survey requiring -- and I think the quote was "the involvement of stakeholders." 123 Can you expand on what form that involvement would take? Is that preview of a survey, or is it simply as one of the respondents to a survey? 124 MR. DINGWALL: I would think that for the survey, if it were to occur, to be useful to the Board, that the questions of the survey, which in any survey could skew the result of the survey, should be drafted not only in previous disclosure to market participants but in cooperation with market participants. 125 The structure of the previous survey addressed the interaction of the competitive market with regulated system supply, and clearly that's not something that the company should be doing in isolation, if it's to be done again. 126 MR. BETTS: Thank you. Please proceed. 127 MR. DINGWALL: The next topic I'd like to address is demand-side management in context of the boiler proposal being put forward by Pollution Probe. 128 Energy Probe was a party to the partial settlement in respect of this and, as such, is a proponent of the settlement and not a proponent of the position put forward by Pollution Probe. The Pollution Probe proposal comes about, and I'm quoting from the settlement agreement which is Exhibit N1, schedule 1, page 33, in the third paragraph: 129 "Pollution Probe accepts the above items but seeks a Board direction for the following additional items: That the company propose and obtain approval for a commercial, institutional, and industrial large boiler market transformation program and shareholder incentive prior to January 1, 2005; and that a budget increase or deferral account be created for the costs associated with any such direction." 130 And listed on the previous page, being page 32 of 57 of the settlement agreement, midway down the page: 131 "A commitment by the applicant..." -- 132 [Court reporter interrupts speaker] 133 MR. DINGWALL: I'm sorry. 134 "...to spend no less than $300,000 of the budget on an efficient large boilers program with an associated volume target of 2.1 million metres cubed for this program." 135 And further down the same page, in the last paragraph, is the company's agreement to file a longer term strategic DSM plan on or before January 1, 2005, which plan will address, amongst other matters, lost opportunity markets, market transformation, low-income customers, incentive mechanisms, and audit protocols. 136 We're kind of curious what might be motivating Pollution Probe to not wait until January 1, 2005 for a longer term strategic DSM plan to address market transformation and lost opportunity markets. Why must it request the Board to direct the applicant to file a plan before the plan? Not just a plan before the plan, but another incentive plan for the shareholder that the company is to obtain approval for before the strategic plan is unveiled? 137 In transcript volume 6, Mr. Klippenstein, counsel for Pollution Probe, reveals the document which has caused Pollution Probe to ask for Board direction to the applicant. 138 At paragraph 291, he reads into the record a Province of Ontario news release from the Minister of Education that announces the Ontario government will help fund $2.1 billion worth of essential major repairs and renovations to Ontario's publicly funded schools. And in paragraph 293 he reads into the record from that same release that the premier said, and I'm quoting: 139 "Funds will flow in the 2005-2006 school year to permit the significant planning required for such a major renovation of school space." 140 And in response to Mr. Klippenstein's direct question that those kinds of major renovations are likely to include new large boilers for some of the schools, Ms. Clinesmith, the witness for the company, was inclined to agree, at paragraph 295. 141 To quote Mr. Klippenstein in his characterization of the announcement as "these billions of dollars being allocated to schools who will now be on a position of studying, among other things, new boilers," at paragraph 296, and the result, "if Enbridge doesn't move quickly, this will be a classic example of very large amounts of money being spent, probably without high-efficiency large boilers being adequately studied or considered," as he questioned the company's panel. 142 Lest we be swept along in the wake of Pollution Probe's alarm that the opportunities might be lost, large amounts are spent, and large, high-efficiency boilers are not going to be adequately studied or considered, Energy Probe would like to submit that the Board examine the Province of Ontario news release. It does not contain even a veiled reference to boilers, large or small. It does not say that there is a provincial government program to replace boilers in schools or anywhere else. It does say that the Ontario government will help fund these major repairs and renovations and that the funds will flow in the 2005-2006 school year to permit the significant planning for the major renovation of school space, not the renovations themselves. 143 And when does the 2005-2006 school year begin? September 2005. So the significant school board planning will take place mainly in the 2006 rate regime, not in the test year. That makes the longer term strategic plan due January 1st of 2005 well placed to deal with the Ontario government's publicly funded schools renovation. 144 Even though Ms. Clinesmith, under cross-examination by Mr. Shepherd, admitted at paragraph 361 that schools are generally very aware of their options in this area, Energy Probe submits that it would be helpful for the Board in its decision to direct the applicant in its longer term strategic plan to consider the education minister's initiative. 145 Those are my submissions with respect to the boiler issue. 146 MR. BETTS: Thank you. We have no questions on that issue, Mr. Dingwall. 147 MR. DINGWALL: Thank you. I'll contain my surprise. 148 Still in the world of DSM, I'd like to address that portion of the applicant's 2005 demand-side management plan that's referred to as the stub period. In that filing, the applicant proposes a volumetric savings target of 25 percent of the savings targets set out in item 10.1 of the settlement agreement in this case, and the same relative proposal for the total DSM O&M budget, being 19.2 million metres cubed and $3.7 million respectively. 149 And fair enough, Energy Probe does not wish to oppose that volumetric target and supporting budget which, to our knowledge, has gained general support among the other intervenors that have an interest in DSM matters. It's the determination of just how the shared savings mechanism will be applied in the stub period that becomes a matter of concern to Energy Probe and others if the Board should grant the requested change in year-end. 150 And the area of concern is whether the test year and the stub period should be treated as two distinct periods of program activity and potential rewards, or if it is more reasonable to combine them into one period. 151 Essentially the company's proposed that it calculate the 15-month-year's shared saving mechanism in two ways: Over the entire 15-month period and over the initial 12-month period only. The company then wishes to retain the right to choose whichever of these two results it will collect from ratepayers. Presumably, the higher reward, regardless of the pattern of the DSM savings or of DSM spending over the 15-month period. 152 While we agree that this proposal maximizes the company's comfort and the transfer of wealth from ratepayers to shareholders, it considers it too generous in principle and an invitation to gaming the timing of both DSM activity and the recording of DSM savings. 153 Turning, then, to Exhibit A7, tab 1, schedule 1, appendix 1, page 3 of 4, paragraph G, I quote from that document, which is at T3 in the event that the Board is following along: 154 "To ensure that no opportunity for gaming of SSM results for the two periods, fiscal 2005 and the stub period, and to protect the company's interests, the company proposes the following safeguards." 155 And the company goes on to propose three safeguards to ensure that there is no opportunity for gaming. 156 Now, with all this company evidence about gaming, one is led to examine whether there exist any other gaming possibilities from which the company has not protected the ratepayer, a gaming possibility that somehow was overlooked in this regime of ratepayer protection. And one such scenario is described in the second listed safeguard as a protection of the company's interests: 157 "Wherein the company exceeds the volumetric target for the fiscal year 2005 but fails to do so in the stub period, in that case, the company proposes that it would still be entitled to the SSM for the fiscal year 2005 and the stub period underachievement should not interfere with its claim irrespective of the size of the underachievement or its effect on the 15-month total DSM saving delivered. In other words, unlike the result wherein the company achieves its 15-month volumetric target, under the stub underachievement scenario, the stub period DSM stands alone, a plan unto itself, and one whose results have no effect on the company's collection of the SSM, regardless of the magnitude of the underachievement and regardless of whether the 15-month total is slightly or even enormously below the 15-month target. Under this scenario, the three-month stub period DSM activity is severed from the rest of the year, off on its own, and without any meaningful incentive to promote DSM savings for ratepayers." And yet, under vigorous cross-examination by Mr. Rowan representing the CME, Mr. Ryckman at volume 11, paragraph 626, admits that the applicant doesn't have a formal plan, much less a stand-alone plan for achieving DSM results in the stub period. And if I might quote Mr. Ryckman: 158 "So it's an extension of the existing plan in some senses, and really, you don't have this kind of stop September 30th, and stop October or start October 1st effect. So a lot of the existing programs are continuing over that period of time." 159 That's the end of the quote. Given the sudden disruption in activity levels that the historic year-end at September 30th has obviously caused, we are concerned that introducing one of two potential ends to the SSM year of September 30th may also lead to a disruption in activity levels around that date, while the company recalculates the options and angles for maximizing its SSM bonus. We cannot see how such a pattern of activity would serve ratepayer interests. 160 Mr. Ryckman has in a number of instances referred to the volumetric target put forth by the company for the stub period as being very aggressive, and the company's reasoning for wishing to split the SSM calculation into two parts is its apprehension that it may not be able to meet the volumetric target which it has proposed for the stub period. It has pointed to the October to December period as being relatively unproductive for the Enbridge DSM programs, historically small despite being cold, having high-volume gas sales, and occurring in early winter. 161 Indeed, as shown in K.11.2, there is a very marked difference between what has been achieved over the years from 2000 to 2003 inclusive in the July to September quarter, when compared to the October to December quarter, an average of 42 percent of the year's savings for the July to September quarter, versus an average of 15 percent for the October to December quarter. 162 The difference is even more marked when comparing what has been achieved in September versus October over the same time period. An average of some 20 percent of the 12-month totals in September versus 4 percent in October, the very next month. And the evidence shows a comparable contrast between unusually high program spending in September and unusually low spending in October. Mr. Ryckman has told us that this is, to some extent, due to administrative lag. 163 So we see a flurry of program spending and volumetric accomplishments heading for the year-end deadline of September 30th, followed by a significant lull in both, apparently starting the morning of October 1st. That huge drop is apparently happening around midnight of September 30th, while Ontarians are closing the cottages and thinking about buying new furnaces and starting to close windows for the winter and thinking of replacing them. 164 And the final point is this. If the company's energetic year-end flurry were combined with a period of even higher customer interest in windows and furnaces and other DSM measures by moving the year-end quarter, it would only be reasonable to expect the delivered DSM volumes and TRC benefits to be much higher than the 42 percent that Enbridge has historically achieved in the old last quarter, being July, August, and September when most Ontarian's minds are focussed elsewhere. If this reasonable expectation is realized, then the company will find it extremely easy to achieve 125 percent of its 12-month target in 15 months. 165 Energy Probe finds the applicant's aggressive volumetric target argument to be somewhat disingenuous, and therefore, the applicant's reluctance to match the extension of the DSM program from 12 months to 15 months with a corresponding extension of the shared savings mechanism, if not due to gaming, to be due to an understandable but unseemly desire to maximize corporate rewards by picking the more generous of two alternative reward systems. And this in a regime which does not have a penalty clause for failure to reach any of the various volumetric targets. So Energy Probe asks that the Board, should it approve the year-end extension, rule that the DSM volumetric target and the SSM calculation be combined into one 15-month period. 166 Those are my submissions with respect to the DSM volume and budget targets. 167 MR. BETTS: No questions on that issue either, Mr. Dingwall. 168 MR. DINGWALL: I'm seeing that it's a quarter to 11. I have a few more topics to cover. Would you like me to shoot for 11 o'clock for a break? 169 MR. BETTS: 11 or shortly after would be fine. And we'll probably be here all day, so I would expect that we'll follow our typical hearing schedule, which would find us breaking for lunch in around the 1 o'clock range. 170 So we'll have a break this morning, a late lunch, and then go through until we finish, ideally. 171 So any time from 11 o'clock to 11:15, if you can find an appropriate break, the Panel would appreciate it. 172 MR. DINGWALL: Well, I anticipate that when I complete my discussion of the next issue, that might be the appropriate time. 173 The next issue I'd like to address is issue 11.2, the class action suit deferral account. 174 This issue gained prominence somewhat late in the going of the hearing, past the date for the posing of interrogatories. The company was good enough to respond to a number of late interrogatories, specifically on this issue from Energy Probe, scoping the issue and responding to some specific questions. As a result, the body of evidence relating to this issue consists of a regulatory history of the issue before the OEB and the verbal evidence of the company witnesses. 175 The body of evidence does not include the decision of the Supreme Court, nor does it include any of the pleadings in the lawsuit itself, including any prayers for relief which might be sought. 176 The questions relating to this issue surround whether it's appropriate for the company to have this account at all, and what type of costs, if any, would be appropriate to record in the account. This was stipulated by the Board in its preamble to the presentation of the witness panel addressing the topic on June 22nd, at paragraph 927 of the transcript: 177 "While the Panel agrees to consider whether to approve establishment of the requested deferral account, it will not be determining whether any of the amounts to be recorded in the deferral account would eventually be recovered from ratepayers. Furthermore, the Panel expects parties to restrict their treatment of the matter to the narrow issue the Panel has to decide. The Panel presumes that any parties wanting to deal with the question of what costs should be included will be directing their examination to the type of cost to be included. It is unlikely that a detailed discussion of forecast amounts would be useful to the Board." 178 In the examination-in-chief, counsel for Enbridge, internal counsel, commented on the time frame over which the litigation might take place, and this took place at transcript paragraph 962 in the June 22nd volume: 179 "MR. BOYCE: Yes, I can. We have corresponded with Mr. Garland's counsel and expect to be meeting with him shortly to discuss procedural issues related to the next phase of the litigation. The next steps are likely to involve proceedings to determine the issues of class certification, quantification of damages and costs. At this point, however, no further proceedings have been scheduled or arranged with the court, but we do expect that at least some portions of the proceedings will occur during the test year." 180 Further along in the evidence in chief, Mr. Ladanyi discussed the general matter of deferral accounts. And this is beginning at transcript paragraph 984 on the same date. And I'm quoting: 181 "Well, the Board has allowed over time the creation of several accounts called deferral and variance accounts to deal with certain circumstances and significant inequities that can arise as a result of the forward test year rate-making process. 182 "In general, the Board has allowed creation of a variance account to deal with budgeted costs, or revenues for that matter, that cannot be forecast with any degree of accuracy or that are beyond management control. Deferral accounts were created to deal with costs or revenues that are so uncertain that not even an inaccurate budget could be produced. Deferral and variance accounts are, therefore, a method of accounting for costs or revenues in a fiscal year so that the Board may deal with them in a later year when their magnitude is known with certainty." 183 In cross-examination subsequent to this, the question of what would be open for the Board to determine in respect of this matter was asked of the company. This is beginning at transcript paragraph 1158, and it's a question that I asked on the occasion: 184 "Mr. Boyce, one of the questions or series of questions that I have relates to what is going to be before this Board to determine versus what is going to be determined by the courts of law with respect to classes and amounts and things like that. Do you have any thoughts at this point in the other proceeding as to what may be left for this Board to determine at the end of the day?" 185 And Mr. Boyce's response at paragraph 1159 was, and I quote: 186 "As part of the litigation proceedings, what the courts will be considering are first of all, as we understand it, the certification of the class that Mr. Garland seeks to create; and second of all, if he is successful in having that class certified based on our reading of the Supreme Court decision, determining the amount that would be payable. 187 Once those amounts have been determined by the courts, we will then be in a position to consider what further actions we may be in a position to bring before this Board, but I'm not sure that really at this stage it's really possible for us to draw a clear dividing line. I mean, it's, again, very early days in terms of understanding how the next steps in the proceedings are going to evolve." 188 And that's the end of the quote from Mr. Boyce. 189 From the comments of Mr. Boyce, we have some concern over whether or not any costs might actually be sought to be cleared from a deferral account in the test year. Mr. Boyce has indicated that, while some litigation may be taking place in the test year, there is no certainty that the litigation would be determinative within that time. 190 Additionally, Mr. Boyce was unable to provide any comfort as to what the dividing line between this Board's labours might be versus what the court might decide in terms of relief. So at this point in time, there's an individual plaintiff seeking what is arguably, prior to class certification, a non-material amount in a proceeding where there has been no certification of a class. 191 What that leads to is a question of whether or not it's possible at this particular point in time to identify what type of costs could be captured in a deferral account. I would think it to be inappropriate for the Board to take any steps which could prejudge the outcome of the court case. And we do not have -- we do not have the pleadings before us in this case as to what the relief that is being sought in the court case might be. 192 MR. SOMMERVILLE: Mr. Dingwall, there's been a deferral account in place for some number of years. Why is 2005 any different? 193 MR. DINGWALL: Mr. Thompson spoke to that, in his cross-examination of the panel, and in his final arguments. 194 The historical deferral account was, for most years, related to the collection, or, pardon me, related to the tracking of the legal costs associated with the defence of the claim. In 2004 the scope of that account changed to include the legal costs and any additional amounts, and I may be not exactly capturing the phrasing associated with that. However, in Mr. Thompson's cross-examination of Mr. Ladanyi on the day in which this panel was in place, Mr. Ladanyi admitted that, due to the somewhat accelerated nature of the proceeding relating to 2004 in which there was no effective issue-by-issue analysis - that proceeding more encompassed the negotiation of what the cost-of-service would be for a very abbreviate proceeding, in order to bring the company back within the regulatory timetable - the merits of the expansion of the scope of the account were not addressed in that process. 195 And the company admits, quite fairly, that they realize now that intervenors were somewhat surprised that in the 2004 process the scope of the account was changed. So they have submitted that for the purposes of this hearing. 196 MR. SOMMERVILLE: That may support an argument that the account perhaps shouldn't include costs of judgment or costs of the plaintiff. But that's the innovation, if it's -- if you can call it that, that it was imposed in 2004. 197 But with respect to the rest of the account, that account has been in place for a number of years now; it's being cleared regularly. Why is 2005 any different on that score? 198 MR. DINGWALL: I would submit that 2005 -- well, what I propose to address, sir, might put things more in context. 199 I'd discussed the types of costs that might flow from a judgment in some brevity. In terms of the other costs that might be appropriate to consider for a deferral account, there are a number of other categories. 200 We've talked briefly about the costs associated with the judgment. There's also been some question of a discussion of the tracking of offsetting costs related to whatever mitigation opportunities might be open to the utility. Mitigation traditionally involves forms of insurance, forms of indemnity, actions against third parties for contribution, all those types of efforts. 201 In cross-examination, Mr. Boyce and the rest of the panel was unable to give any indication of what efforts the company was in the process of making with respect to mitigation. And frankly, I can understand why they would be in that position. Most forms of insurance require some form of confidentiality around the disclosure of what the terms of coverage might be and, additionally, the limits of coverage. As well, the company is in the awkward position of having to identify where and if it is actually sustaining a loss for which it might be seeking recourse. 202 That's where we have a potential conflict in the interest of ratepayers versus shareholders. Because if the company's insurance is contingent on the company itself or its shareholders sustaining a loss, then if the company was in the position to recover any amounts of such a judgment from this class action from ratepayers, it's conceivable that, under some form of coverage, the company might not be in a position to claim against that insurance. It depends whether the coverage extends to losses of its shareholders or losses of the companies or possibly professional negligence in whoever was advising them or other forms of peril. 203 So I think it's reasonable to expect that the company would not want to prejudice itself in mitigation efforts by coming forward with offsetting mitigation costs or offsetting mitigation potential as part of this deferral account. 204 MR. SOMMERVILLE: I understood the company to agree to that. I think the company suggested that they were happy to include, as part of the deferral account, a recording of funds received in mitigation of any judgment, for example. I think the company agreed to that in the course of their testimony. So I don't think that's an issue. 205 MR. DINGWALL: There's a difference between recording the funds received and disclosing the opportunities available to receive the funds. I would think that for there to be a fulsome understanding of that - and this is where we probably have some parallels to the deferred tax issue - there would be a need to not just have the company come forward with what monies it had received, but also to disclose what efforts it was making. That's where the clarity associated with that would be coming from. Otherwise, it's a completely one-sided disclosure. 206 Now, there was some other discussion of what types of costs might relate to the class action with Mr. McGill, in the cross-examinations, and Mr. McGill identified that, outside of the normal efforts of the company in managing its business, it was expending extraordinary efforts in dealing with the challenge of going through millions of billing records over an historical time period to try and ascertain information which would give them an understanding of who class participants might be, what potential entitlement there might be, and what the magnitude of that could be. And this is another type of cost that could be considered for such a deferral account. 207 Now, in terms of what costs we see as appropriate for 2005 to be recorded in a deferral account, it's clear that there is some history with this Board of recording costs of the legal fees associated with the defence of the action. There's some question as to whether those fees be disposed of at this point in time, but I don't believe it's the company's request that they be cleared in the test year. We would be content with the continuing of the recording of the legal fees, within the deferral account. 208 With respect to the costs of Enbridge Gas Distribution expending extraordinary efforts with respect to understanding the nature of the billing information and trying to recreate those records, we think that those costs should be identified by the company, separated out from the operations and maintenance budget or identified as where they fit within that budget, where they fit outside of that budget, and recorded in the deferral account. 209 With respect to the costs of any amounts that might be ordered to be paid by a court, I think it's premature to consider the recording of any of those amounts until there is the full opportunity for the courts to exercise their jurisdiction and for the Board to understand where the extent of the courts' jurisdiction ends and its jurisdiction begins. That was the point Mr. Boyce made about not knowing what questions are in this room versus not knowing what questions would be resolved in the courthouse. 210 With respect to the recording of costs which might be offsetting through mitigation, it's our submission that those, as well, do not need to be recorded in the deferral account at this point in time either, as there is significant uncertainty as to the time period that they might be understood over, as well as whether or not mitigation is, in fact, required given that there is no decision from the courts. 211 And those are my submissions with respect to the deferral account associated with the class action. I welcome the Board to consider questions or the opportunity for the break. 212 MS. NOWINA: I have a question, Mr. Dingwall. Just a very simple one, clarifying your recommendation. 213 You suggest that the legal costs be continued to be recorded in the deferral account, but the judgment not be in the deferral account. Would you consider the legal costs of the plaintiff to be part of the judgment or part of the legal costs? 214 MR. DINGWALL: I would consider them to be part of the plaintiff, because -- or pardon me, I beg your pardon, I would consider them to be part of the judgment, because the company would not be accruing a liability to pay those costs until the point of judgment. 215 MS. NOWINA: Okay. Thank you. 216 MR. BETTS: The Panel has no further questions on that particular issue, Mr. Dingwall. So this would be an appropriate time to break. Let us aim at returning at 25 minutes past 11. 217 --- Recess taken at 11:07 a.m. 218 --- On resuming at 11:29 a.m. 219 MR. BETTS: Thank you, everybody. Please be seated. 220 Before we resume with the arguments or submissions from Mr. Dingwall, were there any preliminary matters that arose through the break? 221 Mr. Dingwall, back to you. 222 MR. DINGWALL: Thank you, sir. I'll assume that the Board has reached an appropriate level of caffeine-ation for me to move on to deferred taxes. 223 MR. BETTS: Not fully. We're getting there. 224 MR. DINGWALL: Energy Probe's exhibits provide highlighted copies of the Board's EBO 179-14/15 decision, and, found in a box at the back of many, many cupboards, a copy of Energy Probe's argument that was presented in that case. And this argument relies on the terms such as Rentco defined in the EGD argument in-chief. 225 By way of overview, the company is seeking to recover from the notional utility account established as a result of the EBO 179-14/15 decision the sum of $23.9 million after tax. The time period of requested relief is from October 7, 1999 to May 7, 2002. 226 The focus of Energy Probe's argument will not be on the details of technical tax treatments, where the Board has already benefitted from the extremely able submissions of Mr. Shepherd, nor will we be going into as much of a history lesson about what's been before the Board at various times as Mr. Thompson has canvassed that subject with a significant amount of detail. Rather, our argument is going to focus on the regulatory treatment of EGD's deferred tax claim. Specifically, the core of Energy Probe's argument on deferred tax is captured, really, by one word: Prudence. We understand the word "prudency" is up to debate as to whether or not it actually exists, so we'll use the word "prudence." 227 In cost-of service regulation, the Board must determine the prudence of expenditures. The regulatory compact, a phrase which really came out as a result of the evidence of Kathleen McShane in the 179-14/15 case, requires customers to pay just the reasonable costs of the monopoly service provider. 228 With regard to EGD's claim for deferred tax recovery, Energy Probe believes that the Board must focus on the prudence of the incurrence of the claimed costs, and the visibility of that incurrence. 229 As discussed in the Board's 179-14/15 decision at paragraph 2.5.1, the company indicated that the equipment rental business was not viable at that time, and that the company was planning to wind down the rental business. In fact, in 1999 the applicant testified that it was not feasible for the rental program to be sold either to an affiliate or a third party. 230 And that cite occurs at the eighth transcript volume, at paragraphs 1074 to 1075, and 1083, which I believe is quoted in the decision, yeah, of EBO 179-14/15. 231 And at tab 5, page 2 of the materials that Energy Probe has provided for today's purposes, there's a highlighted section from Energy Probe's argument in that case, which states as follows: 232 "Energy Probe notes that there may be more efficient alternatives to the wind-down process that the company decided not to present to the Board in this application. Energy Probe relies on the evidence of Dr. Bauer" - and there's a reference - "who makes it clear that unbundling is beneficial but that the company's wind-down proposal should be rejected on the grounds that the company has not provided a quantitative assessment showing that this proposal minimizes the impact on ratepayers relative to the sale option; that there is no evidence that the wind-down would enhance efficiency over other options; and that the extent of cost subsidies would remain unknown under the wind-down." 233 Selling the entire rental business perhaps in small pieces, including its deferred tax liabilities, might mitigate the negative impact proposed by the company. As noted in paragraph 3.2.7 of the Board's decision in that case, the company has stated that it does not wish to continue the rental program as a going concern, partly because it is unprofitable to do so under the fully allocated costs. 234 In hindsight it is now abundantly clear that the wind-down approach was not necessary and probably was not intended, even when the company claimed the opposite intention. From the perspective of EI's overall business, the wind-down never happened. The wind-down happened only in an artificially isolated corner of the company. The wind-down was purely a contrivance to use the letter of the Board's decision to expand EI's net recoveries from captive EGD ratepayers. 235 The company made no attempt to minimize tax losses in Rentco. This is what Mr. Boyle had to say on that, in the ninth volume of the transcript, at paragraph 460, in response to a question from Mr. Thompson. And I can't do Mr. Thompson's voice, so I'll have to do this in my own voice: 236 "All right. Let's move forward, then, with the appropriateness of confining this calculation to October -- to pre-October 1, 1999 assets in the context of the reality that there has been no wind-down of the business. There has been no wind-down of the business; correct? Or there was no wind-down of the business?" 237 To which Mr. Boyle responded: 238 "There was no wind-down of the ongoing rental program, that's correct, but there was a wind-down of the costs and benefits associated with the utility rental assets. All of the new assets were non-utility, non-regulated assets. The risks and rewards and costs and benefits, all of which belonged to the non-utility businesses and operations should not be related to the utility rental asset pool that generated the benefits to ratepayers." 239 To which Mr. Thompson responded: 240 "But the expansion of the business that took place after October 1, 1999, and the rent increases that were imposed, all of that was used to support the viability of the business and was eventually sold to Centrica on May 7, 2002. Everything transferred to Centrica." 241 To which Mr. Boyle responded: 242 "Yes, they did. All the businesses, the businesses noted in my undertaking response to Mr. Shepherd earlier today." 243 That's the end of the quote. 244 In paragraph 3.2.8 of the 179-14/15 decision, the Board stated: 245 "Whatever the company's motivation in proposing the wind-down of the rental program, the Board is not convinced that it is either necessary or the best solution in the circumstances." 246 In EBO 179-14/15, the applicant's evidence foreshadowed the plan it eventually used. The company testified that the magnitude of the transition costs would be affected by the decision as to who would bear the costs. Energy Probe remarked in argument that this approach was odd and disturbing, in hindsight. It is clear that the effort the company exerted toward what might be called tax engineering greatly outstripped the effort that went into minimizing the exposure of ratepayers. 247 Energy Probe suggests that, in framing its decision, the Board should concentrate on Rentco and only look beyond it into other unregulated EI entities to test the prudence of the tax approach adopted within Rentco. The wider business activities of EI, under which unregulated rental assets were expanded thereby offsetting taxes coming due on formerly bundled utility rental assets, demonstrate that the taxes payable at Rentco did not have to be payable during the period from unbundling until eventual sale. 248 In 179-14/15 the company's evidence was that the potential for rental income was severely constrained. As documents detail in the arguments of School's and IGUA, rents were increased and assets added. An example of this being acknowledged on the record occurs at volume 9 of the transcript, at paragraph 341, with Mr. Thompson beginning: 249 "Okay. But the bottom line was, rents were increased by 19 percent, give or take, on March 2000. 250 Mr. Boyle responded "Yes," to which Mr. Thompson responded "Subject to check," to which Mr. Boyle responded "Subject to check, yes." 251 Mr. Thompson's subsequent question was: 252 "And then the evidence, Mr. Fournier's evidence indicates that there was a further rent increase January 2002 of about 5.5 percent. Could you take that subject to check?" 253 To which Mr. Boyle responded "Yes, I would." 254 In the current case, much has been made of the distinction between taxes paid versus taxes payable. In its decision in 179-14/15, the Board supported recovery of some deferred tax costs as they come due. However, there was a clear expectation of the Board that these recoveries would be made on the assumption that the program would be efficiently managed. 255 At paragraph 3.2.4 the Board specifically directed the company to minimize costs by operating the program as efficiently as possible. Here are the Board's own words commenting on why it rejected keeping the rental program on a wind-down basis for the utility as proposed by the utility: 256 "The extent of any cross-subsidization the ratepayers would be unknown and there would be little incentive for the company to operate the program as efficiently as possible." 257 The Board reiterated this thrust at paragraph 3.3.21: 258 "If the company decides to continue the program, it will have an incentive to run it as efficiently as possible, since it must account for it on a fully-costed basis." 259 With respect to this, the next area relating to deferred tax is about information deficiencies in the applicant's evidence. 260 Regulation of a company as large and complex as Enbridge Gas Distribution, which is part of an even larger and more complex utility holding company, is difficult. There are complexities on many levels. Understanding these issues at a detailed level requires expertise in fields that range from administrative law, engineering, finance, economics, labour law, pension management, and on and on. 261 Corporate tax planning is itself a highly specialized technical profession where up-to-date knowledge requires continuous reinvestment. 262 Given its great complexity and the informational asymmetry between the regulated firm as compared with the Board and the intervenors, combined with the monopoly nature of cost recovery in this sector, the regulatory process rightly places an informational onus on the regulated utility. Regulation cannot function without clearly and fairly presented information. Incomplete and inadequate disclosure has afflicted the issue of rental program costs at least to fiscal 1998. In paragraph 3.3.9 of the Board's decision, EBO 179-14/15, that Board noted: 263 "The Board expressed its concern in the EBRO-497 decision that the costs relating to diagnostic services had not been identified previously in the fully-allocated cost study which had been presented to the Board in EBRO-495. The result of this failure was that the true revenue deficiency of the programs in fiscal 1998 was not recognized. The company had, in effect, a transition period in which fully allocated costing did not apply to the programs. The Board declined to provide any additional transition period and directed that full costing continue to be applied. In addition, the Board expressed its concern as to what other costs properly belonging to either ancillary or non-utility activities are still missing in the company's cost allocation. It now appears that the unrecorded deferred taxes relating to the ancillary programs were another such cost, and a large one." 264 That's the end of the quote. As documented above, many of the key statements of the company witnesses in EBO 179-14/15 were incorrect. In that case, EGD's predecessor brought a witness, Kathleen McShane to present the company's view of what it called the regulatory compact. Providing appropriate information is essential to the proper functioning of the regulatory compact. The company's enthusiasm for the regulatory compact apparently was forgotten throughout the presentation of evidence related to the rental program. 265 As documented extensively in the submissions of Schools and IGUA, Mr. Boyle's evidence on issues like the application of the matching principle in accounting, upon which the company relies heavily in its argument, was not clear and complete. 266 The Board's decision should remind the company, as the Board reminded the company about matters like revenue offsets against O&M and reporting related to affiliated companies in previous cases, that evidence should be presented in a fashion that is clear and complete. 267 And in conclusion on this particular issue, from the perspective of ratepayers, the records in this and previous cases demonstrate conclusively that the income tax liabilities associated with Rentco were not prudently managed by the applicant. 268 In addition, the applicant's evidence was proven to be unreliable. The Board should conclude from these facts that no relief should be granted to the company for deferred taxes associated with the rental program becoming payable. 269 Both SEC and IGUA applying the principles set out in the 179-14/15 decision that whoever is responsible for the payment of the deferred taxes should be entitled to this credit, recommended that the $36.3 million in Canada Revenue Agency refund received by Rentco be credited to ratepayers. Energy Probe supports this recommendation. If the Board identifies any taxes payable from Rentco, the CRA refund should be used to offset the payable amount. 270 And one more additional point is that the informational asymmetry seems to extend to the company taking a separate approach in terms of its cost allocation, post-separation, versus how those cost allocations apply to taxes. It's our understanding that, prior to the separation of the rental assets into Rentco that the utility would use the increases in rental rates such as they came about, to offset many of the ongoing obligations of the program, including, as well, partially the tax obligations. 271 It's in evidence in this proceeding that the rental rates for the hot water heaters were raised after the separation of the hot water heaters from the regulated utility, somewhat in contradiction of the company's evidence as to the market actually being in a position to accept any increase in rental rates. It seems a natural offshoot of that that the increase in rental rates should have been used as one of the mitigating factors offsetting any taxes the company was claiming as had been historically done when the assets were in the regulated utility. 272 And I'll take a moment to pause in the event that there are any questions on this particular issue from the Panel. 273 MR. BETTS: Mr. Dingwall, you've made the statement, and correct me if I've not heard it right or if I've misinterpreted it, that the taxes were not prudently managed within Rentco. Am I correct, first of all, with that statement? 274 MR. DINGWALL: Yes. 275 MR. BETTS: Can you help me understand how you drew that conclusion? 276 MR. DINGWALL: I'm going to ask Mr. Adams to respond to that sir. 277 MR. BETTS: I'll accept that. Thank you. 278 MR. ADAMS: Sir, the evidence of the company at 179-14/15 was that it was going to wind down these company assets. In the Board's ruling in that case, the Board expressed concern about the approach that was being proposed. And the cites that Mr. Dingwall quoted identified the instances of the Board's concern about the efficiency of management of liabilities within Rentco. 279 The claim that the company is making in this case appears to have arisen in a fashion that makes it clear, from the evidence, that the company did not -- was not mindful of the guidance provided in that ruling. It did not make reasonable efforts to minimize the exposure of ratepayers to the deferred tax claim. 280 It's clear from the evidence, that there were options available to the company that they, in fact, utilized outside of Rentco, in the extended EI family. But the argument we're putting before you does not rely on directly drawing the tax treatment of non-Rentco EI assets into a calculation, as relied upon by IGUA and CEC, and Schools, in their arguments. 281 The thrust of our argument is only that the demonstrated experience of mitigating the tax liability through other EI business activities demonstrated that it was possible to achieve that mitigation within Rentco, but that mitigation was not pursued. Hence, that's the basis upon which the claim is before you today. 282 MR. BETTS: Thank you. We have no further questions on that issue. Thank you. 283 MR. DINGWALL: That brings us, then, to the discussion of the change in the company's year-end. Without the assistance of visual aids, we will attempt to put this issue in context. Quite simply, in the forward test year world in which we live, the company's earnings are a function of their revenue and expenses for a specific time period. 284 The status quo is the company having 12 consecutive months as the measurement period, which bears with it all the attendant cycles in consumption and revenue. 285 The company is proposing to move from the September 30 year-end to a calendar year-end, and in so doing is proposing that the three-month period between the previous year-end and the beginning of the next year have a different treatment in respect of the rates for that period, being a rise in the revenue requirement approximating a CPI-type increase. 286 It appears uncontested that the interim period, which has gained the common term stub period, is a period in which the company's revenues are traditionally higher than other quarters. What is contested is whether that period can be treated in isolation or whether it must be viewed in context of some additional quarters in order to give it context. 287 An alternative to the forward test year rate-making model is what is known as the rolling 12-month model, in which case each quarter is measured in context of those periods around it. It should be clearly understood that this is a different rate-making model, with completely different precepts and functionalities than the forward test year model. A rolling 12-month test year presumes that there are adjustments to earnings on a live basis and an ability for the regulator to step in if there is a significant interperiod fluctuation in earnings. 288 This does not exist in this case. Enbridge's application appears to be tantamount to there being no treatment of the stub period whatsoever. It would either be ignored, if rates from this current 12-month test year continue and the next application is filed in respect of the calendar year, or obfuscated in some future filing which attempts to display a rolling 12-month report in the isolation that the rates are not going to be in place on that basis. 289 We submit that the only way of viewing this stub quarter is in isolation, as an adjunct to a normal 12-month period. There are two ways in which this could be done. The first of these would be to direct a 2006 filing, include this period, and that that filing be for 15 months; the second would be for the company to file a separate application for rates solely for the three-month period. 290 We don't believe that it's possible for the company -- or, pardon me, for the regulator, to take a stab at estimating what the expenses might be for the company during the stub period. The company's evidence with regard to what its forecasted expenses during that time is, the ink is still wet on that one. And there was no cross-examination on that; there was no testing of it. So we submit that it would be unfair for all for the Board to impute 15 months' rates from that. 291 What we do believe would be possible would be either directing the company to include the three-month period in its next test year filing, or 15-month rates, so that the period can be viewed in context; or considering some form of overearning protection in context around what the company's return on equity should be for the current test year as proposed, plus the three-month period, with some retroactive adjustments to address the potential overearnings. 292 In listening to Mr. Shepherd's arguments, we were convinced that he'd spent a lot of time on deferred taxes and that maybe that's where everything ran out for him. We disagree with the suggestion that if the company were filing for a rate -- if the company were filing for an alternate period in which the rates would be going up, that intervenors would disagree with that. 293 Frankly, I think if the three-month stub period that we were going to be addressing in this proceeding included significant underearnings, it would be more of a natural assumption that the company would have been in a position to provide 15-month figures and stub figures far more readily, and we'd have addressed that at the time that we addressed the global settlement on O&M issues. 294 Now, with respect to each of these approaches, that leaves the questions of what should be done with demand-side management and transactional services forecasts. 295 With respect to demand-side management, if the Board is not going to direct that the three-month stub period be dealt with in a separate rate-making proceeding or as part of the subsequent test year, then we would suggest that for DSM purposes a 15-month DSM forecast, as we discussed earlier, should be used with a shared savings mechanism applying to the whole period, not any portions of that period. 296 With respect to transactional services, our view is that a pro rata forecast again should be attributed to the stub period, and that, in the event that we are dealing with 15 months in this application, with an overearnings protection, that transactional services forecast cover that 15 months; otherwise, we stay with the 12 months and the Board direct the new forecasting for the three-month period to be brought in one of the other possible applications. 297 Those are our submissions with respect to year-end. 298 MR. BETTS: The Board Panel has no questions on that issue either, Mr. Dingwall. 299 MR. DINGWALL: That brings us to the final two issue, the first being issue 15.1, the proposal to remove rate seasonality for all rate classes except rate 135. 300 In its initial filing, the company proposed a number of cost allocation and rate design changes in this case. The main proposal was a range of changes related to cost allocation for transmission and storage costs and some proposed changes to customer charges for certain rates. 301 All of the proposed changes were subject to complete or partial settlement. The only proposal Energy Probe does not support is the proposal to remove rate seasonalization. Looking at all of the cost allocation rate design proposals other than deseasonalization, the common thread through all of these proposals was that, in each case, the proposed changes moved in the direction of cost causality. Energy Probe supported all settlements that moved in the direction of cost causality. 302 In particular, I want to bring the Board's attention to Energy Probe's support for increases in customer charges for rate 1. Not only would an increased customer charge for rate 1, as proposed, improve cost causality, but this change will also incrementally move in the direction of year-over-year revenue stability for the utility, a development that can hopefully, in the long term, reduce the risk profile for the utility. 303 Energy Probe's cross-examination on this point, including the company's agreement that increasing the customer charge moves incrementally in the direction of revenue stability for the utility, is at transcript volume 6, paragraphs 778 to 791. 304 Thrown in among this basket of sensible changes is one that sticks out like a sore thumb, the proposed deseasonalization of rates for all but rate 135. The proposed deseasonalization is the one instance in this case of a proposed change moving in the direction away from cost causality. Energy Probe suggests that any benefits of deseasonalization would be de minimus. The status quo is directionally better than the proposed change. 305 Where the company argues that the change simplifies rates, Energy Probe submits that what is achieved isn't justified simplification, but dumbing down rates and removing directionally correct economic signals, albeit modest ones. And while the company points out that seasonalized rates are rare in Canada, it would appear that the direction that the government is moving the Province of Ontario towards is more of a conservation-based culture, rather than a consumption-based consideration. And seasonalization is an incremental step in that direction. 306 The company recognized that it faces risk due to erosion of hot water heater loads, which generally have favourable seasonal load shapes relative to overall utility asset utilization. Recognizing that the rate advantage from the status quo seasonalization to water heating applications is modest, the rate advantage to the status quo is beneficial to maintaining that load against competition with generally less efficient electric water heaters. 307 And then in thinking about where we go in the future, in Exhibit H1, tab 1, schedule 3, paragraph 4, the company states that one of the deficiencies with the current seasonalization approach is that the current seasonal differential provides only partial recovery of seasonal costs. Energy Probe agrees with that observation, but suggests that the solution is not to collapse the existing seasonalized differentiation of rates but to move further in the direction of seasonalized rates. Load-balancing costs reflect a large portion of the seasonal cost of serving customers. Despite this fact, load-balancing charges are the same throughout the year. The Board should urge the company to review its rates with a view to implementing rate changes that reflect more completely the difference in cost of delivering gas during the design peak period in winter and non-peak periods. 308 And that has us reach the end of Energy Probe's submissions in respect of the outstanding rate issues. It's my suggestion that, rather than make the verbal submission as to costs at this time, that it might be more stream-lining of the procedure if we did so in accompaniment with the written submission. 309 MR. BETTS: Thank you. That's a good suggestion, Mr. Dingwall. And we have no questions on the submissions on the last issue. And am I correct that that completes, then, your submissions, Mr. Dingwall? 310 MR. DINGWALL: You are correct, sir. Thank you very much. 311 MR. BETTS: Thank you very much. The Board appreciates those. And I'll say this to you and anyone else, that the Board doesn't expect you to stay the entire day to hear all of the submissions provided orally, so you are welcome to leave as soon as you're done with your responsibilities. 312 Mr. Janigan, are you prepared to proceed at this time 313 MR. JANIGAN: Yes, we are, Mr. Chair. 314 MR. BETTS: Would you please do so. 315 MR. JANIGAN: Thank you, Mr. Chairman. 316 SUBMISSIONS BY MR. JANIGAN: 317 MR. JANIGAN: I am here to present the final arguments of the Vulnerable Energy Consumers' Coalition. There is information about the Coalition under tab 1 of our book of references, and I wonder if it's possible, at this point in time, if the Panel has that book of references, that we can give that book an exhibit number. 318 MR. SCHUCH: And I believe the Panel does have copies of this book of materials? 319 MR. BETTS: We do. 320 MR. SCHUCH: And we will assign, then, Exhibit K.15.3 to these materials, entitled, "Argument of the Vulnerable Energy Consumers Coalition, July 14th, 2004, book of references." 321 EXHIBIT NO. K.15.3: ARGUMENT OF THE VULNERABLE ENERGY CONSUMERS COALITION, JULY 14TH, 2004, BOOK OF REFERENCES 322 MR. BETTS: Thank you. 323 Thanks, Mr. Janigan. You can proceed. 324 MR. JANIGAN: Thank you. In this oral argument, Mr. Chair, we'll specifically address issues not resolved in the settlement agreement by major topic. And those include transactional services gas transportation and storage costs, the RiskAdvisory report, and Enbridge's response to the RiskAdvisory report, the 2005 class action suit deferral account, demand-side management issues, the boiler issue, and the treatment of the stub period, the issue of deferred taxes and the notional utility account, the change in the fiscal year-end and rate design. 325 What we've attempted to do is incorporate in our book of references excerpts from key evidentiary and transcript references, and I will point them out briefly during my presentation by reference book and tab number or page number. I may not necessarily linger long over those references, except where I need to linger to emphasize the point made in the argument. 326 So the first issue we will deal with is the issue 4 of transactional services. And there are a few references that I will be referring to, and those are covered under tab 2 of the reference book. And in particular, if you could turn up first tab 2, pages 6-3, Undertaking K.4.2, revised. And with reference to the column "with commodity," the transactional services gross margin for 2005 is $15 million, which is composed of $8 million of asset-based transactional services and $7 million of commodity-based transactional services. The company proposes to continue the sharing arrangements negotiated as part of the RP-2002-0133 settlement agreement. 327 Under the sharing arrangement, assuming bundled asset commodity transactions are included, ratepayers will be guaranteed the first $8 million in gross margin with the next $2.7 million going to the account of the shareholder, and any remaining gross margin shared 75 to ratepayers and 25 percent to the shareholders. The shareholder is responsible for the marginal O&M costs. 328 Given a $15 million gross margin forecast, VECC would of course prefer a higher ratepayer guarantee of $10 million, but the time for this negotiation is past, and accordingly, we reluctantly accept $8 million to be embedded in rates and the company's 75/25 transactional services revenue-sharing proposal for the 2005 test year. 329 Now, with respect to the stub period, October 1st, 2004 to December the 31st, 2004, should the Board order include this period, then VECC accepts the pro rata sharing proposal that was put forward by the company for the stub period. And that's found at tab 2, page 7 of our reference book. If the stub period is included and that shared proposal put in place, it would be an additional $2 million for the ratepayer and the next $675,000 for the shareholder, with the rest being split 75/25. 330 The amounts quoted assume that the bundle-asset commodity transactional services are accepted by the Board, the package, the bundled asset with the commodity transactional services are accepted by the Board. The issue of who should conduct the bundled asset commodity transactions and the related issue of credit costs is discussed under issue 4.2, which I propose to deal with now. 331 Like other ratepayer representatives, VECC does not accept that the utility and its ratepayers should be exposed to the risks associated with the bundled asset commodity transactions in EGDI's name. The company's proposal is to offer commodity sales in conjunction with transactional services for EGS to conduct commodity transactions in EGDI's name and to deduct credit costs from gross margin prior to revenue-sharing. 332 Also, ratepayers are not willing to accept the credit costs that EGS/EI claim are incurred if EGS carries out the commodity portion in its name and for which EGS and EI wish to be compensated by deducting credit costs estimated to be approximately $2 million from the gross margin before sharing of revenues from transactional services. 333 Now, we expect that some intervenors will propose that the Board impose an absolute ban on bundled asset commodity transactions for competitive reasons, and will claim that by prior Board decisions, including RP-2001-0032, only pure asset transactional services transactions are allowed. 334 VECC disagrees with this submission and states that there is clear evidence that including commodity as part of the bundled asset commodity transactional services yields higher revenues to reduce rates for the ratepayers, who underpin and pay the cost of these assets. 335 You can see that at -- once again, in our book of materials, tab 2, page 6-3, Exhibit K.4.2. The difference between "with commodity" and "without commodity" columns is $5 million for ratepayers, and that's found on line 14 of that particular exhibit. 336 The evidence of the company is that there are three options for conduct of transactional services business in 2005, and these are shown in the last three columns of Exhibit K.4.2 that I just referred to. 337 The first option is EGDI to authorize EGS to conduct bundled asset commodity transactions as agent for EGDI with the commodity portion being conducted in EGDI's name, and EGDI bearing any additional costs, such as electronic trading and counterparty failure for risk coverage. 338 The second option is to continue to have EGS conduct bundled asset commodity transactions with the commodity portion in EGS's own name, in which event the credit costs incurred by EI, estimated as up to $2 million, would be deducted from the gross margin prior to sharing. Now, the company has clarified that the proposal results in the sharing of the credit costs 75/25, but the net effect is $2 million more from ratepayers -- from the ratepayers going to the shareholders. 339 The third option is to revert to the traditional asset transactional services only and exclude the bundled asset commodity transactions. In this event, the gross margin forecast for the 2005 test year would be reduced from 15 million to about 8 million, and we've already looked at that $5 million difference in K.4.2. 340 VECC's preference is for option 2, which, in essence, maintains the 2003-2004 status quo. VECC submits that, regardless of the Board's decision on the policy background associated with the inclusion of bundled asset and commodity transactions, that EGDI and its ratepayers should not be exposed to the risks of gas commodity trading beyond the risks related to the management of utility system-gas -- utility system-gas supply portfolio. Accordingly, if bundled transactions are to occur, EGS should conduct the commodity portion in its own name. 341 Now, it's clear from the cross-examination of the EI corporate treasurer, which you see at tab 3 of our exhibit of materials, page 9, which contains transcript volume 4, paragraph 476, that the credit costs that are claimed by EGS/EI are an opportunity cost related to the requirement that EI ensures that there is adequate equity to support its fixed obligations, including those of EGS. And secondly, the pricing takes place at a target cost of EI common equity estimated at 15 percent after tax. 342 Now, the company has filed information that shows that EI may provide EGS with letters of credit, since EGS is, essentially, an emperor without any clothes. 343 In VECC's view, the claim for compensation for EI credit costs is nothing more than a revenue enhancement or a money grab that has been concocted by EI; that, if accepted, would effectively increase the shareholders' share of the total transactional services revenue from 25 percent to 40 percent in 2005, and the shareholders' total gain by $2 million. 344 If we look once again at K.4.2, which is at page 6-3 of tab 2, you have to increase the shareholders' share at line 15 in the column. That assumes EGS still does commodity by $2 million, from 2.58 to 4.58 million, unless you were convinced there was a real cost to EI, not just an notional opportunity cost that EI charges to EGS and now EGS seeks to recovery from EGDI. 345 And it is important to note on the subject of notional costs and benefits that not all notional costs and benefits are allocated and paid in the regulatory process. A good example of this is goodwill, and in particular, goodwill associated with a utility name. 346 While it is clear that a utility name has some value when used in conjunction with other businesses or retail offerings by corporate entities carrying on the -- carrying the utility name, goodwill is not treated in a fashion that allocates -- allocates its value in the same manner as any other asset in the rate base of the company. 347 When the utility name is used to market products to ratepayers who have acquired familiarity with the name by way of their customer relationship with the utility, one would ordinarily assume that the utility has paid a royalty that would help reduce its revenue requirement. 348 The answer from this Board is, no, that goodwill does not appear on the books in rate base; therefore, no royalties need be paid. The OEB advisory report to the Minister of Environment and Energy on utility diversification of May 15th, 1996, clearly noted at paragraph 5.6.6 of its decision that: 349 "Since the royalty would not be cost-based, it would run counter to the objectives of cost-based rates and cost-of-service regulation. The Board also considers that the royalty concept is at odds with the practice that goodwill is not an asset appropriately included in the determination of rate base." 350 What was established in the cross-examination of the witnesses is that this is clearly not something on the books of EI. This is a notional concept for which they are now claiming compensation. And, as we indicated, not all notional costs and benefits, even when they have some basis in reality, such as goodwill, are claimable in the regulatory process. 351 VECC submits that the precedent is that the Board can only allocate costs on an actual, not a theoretical basis, and cannot credit the company for costs that don't appear on its balance sheet. 352 There's one new development that I should comment on. In the company's argument in chief, Mr. O'Leary suggested first that the $2 million credit cost should apply to the 2005; and second, that the costs should be deferred pending an independent consultant's report. And you'll find that, Mr. O'Leary's comments, at tab 3 in our book of materials, page 10, transcript volume 13, paragraph 464. 353 VECC disagrees with this approach, since the company is seeking a deferral account for a cost that, until it has been found to be legitimately recovered from ratepayers, is just a claim. In addition, the evidence supporting this claim is, at the present time, highly questionable. We hope that the Board will deny the claim until it has been verified as a legitimate and verified cost incurred by EI for the benefit of ratepayers. This is the same criterion that the Board has applied to cost incurrence related to corporate charges. 354 VECC submits that this new proposal for compensation for credit costs places into question the overall benefit costs of the agency agreement between EGDI and EGS and EI. VECC submits that either EGDI should be directed to either seek a more cost-effective arrangement with a third-party service provider that would yield improved benefits and lower costs to ratepayers for both management of system gas and transactional services; or, as per the requirements of the Affiliate Relations Code, EGDI should demonstrate that the costs charged by EGS for services represents fair market value. Until this is done, the credit costs claimed by EGS/EI in 2005 should not be taken off the top, and 100 percent of the gross margin should be the basis for sharing. 355 It's important in the consideration of this matter, to note that we embarked upon this incentive procedure in transactional services to enhance the additional revenue to be obtained from assets surplus to the franchise customers to reduce revenue requirement. We, in effect, chose to override the natural assumption that ratepayers obtain all transactional services revenue because they paid for the assets. And we did this because we thought that the company could do better if there was something in it for them, to market these transactional services. 356 We've now come a full circle. The incentive itself is now a target for revenue enhancement by the parent and the company exhibits an approach that largely ignores how the company got the opportunity to earn something for its shareholders in the first place. And we have noted Mr. Thompson's comment of yesterday's date with respect to the parent's involvement with the affairs of the utility. 357 That concludes our submissions on the subject of transactional services and sharing of credit costs. 358 MR. BETTS: The Panel has no questions on that particular issue, Mr. Janigan. 359 MR. JANIGAN: My next topic is issue 5.0, gas costs, transportation and storage. And the background and other references for this issue are at tab 4 of our book of references, starting at page 12. And as the Board is aware, in the settlement proposal of June the 11th, 2004, parties accepted the company's forecast of gas, transportation and storage costs for the test year with the exception of the cost consequences of the new contract for Union storage. The evidence associated with the cost consequences for the new contract for Union storage was filed on May 17, 2004, well after the interrogatory process for this proceeding. In the result, parties have had little opportunity to explore the reasonableness of the contract until the oral hearing process. 360 The issue to be determined in this proceeding is the cost consequences of the new contract effective April 1st, 2004, to be recoverable in rates either through the clearance of the amounts recorded in the 2004 Union Gas deferral account or in rates for 2005 test year and beyond. 361 Furthermore, there is concern by some intervenors about the advisability of entering into a ten-year commitment in light of the Natural Gas Policy Forum. According to the evidence filed, and that evidence obtained upon cross-examination, Enbridge is seeking Board approval to replace a cost-based storage and transportation contract, this being contract number M12001, that is to terminate March the 31st, 2006, with negotiated storage and transportation contracts to be effective April the 1st, 2004, and to run to March 31st, 2014. These contracts include a new storage contract, which is contract number LST039, an easterly firm transportation contract, contract number M12079, and a western firm transportation contract, contract number C10050. 362 From the evidence and from the evidence elicited in cross-examination, it is apparent that the replacement contracts will result in the storage component of the original contract to be priced in excess of the cost-based rates under the C1 rate. The new eastbound firm transportation contract will be priced in the same manner as the original contract under the M12 cost-based rates. 363 The westbound firm transportation contract previously provided to Enbridge at zero cost, excluding fuel, will now be priced at a negotiated market price under the C1 rate. However, for the period April 2004 to March 31st, 2006, the westbound firm transportation component will remain at zero cost, exclusive of fuel, since, as the company pointed out in cross-examination, EGD would not pay anything for this service in the first two years and the negotiated rates under C1 for this service would commence April the first, 2006. 364 From a cost-consequence perspective only, the new storage contract will have an impact on the 2005 test year through the 2004 UGDA and 2005 storage costs. From the cross-examination of the company witnesses, it is clear that the Board does not approve the cost consequences of this -- if the Board does not approve the cost consequences of this new storage contract, the pricing of the original contract would revert to cost-based rates from April 2004 to March 2006, at which time Enbridge will need a new contract for 20 Bcf of storage at market-based rates. 365 Now, in the RP-1999-0017 proceeding, VECC urged the Board not to approve the renewal of M12 contracts for interprovincial utilities, EGD, NRG, Kitchener and Kingston, and their customers at market-based rates, as it was our view, and remains our view, that ratepayers in Ontario should benefit from cost-based storage. 366 VECC continues to support this view that storage is a physical provincial asset that should benefit Ontario ratepayers and should remain at cost-based rates so that the market premiums from storage are not reallocated to the LDC or marketers. 367 Furthermore, VECC is of the view that by allowing market-based storage, the only result is higher energy costs for end-use customers. VECC hopes that the Board will review the concept of cost-based intra-provincial storage and transportation rates in the upcoming Natural Gas Forum. Accordingly, VECC submits that, in the interim, the Board should not approve the new ten-year storage contract at market rates proposed by Enbridge. In the result, there will be no long-term contractual obligation that would inhibit the Board from altering its view to re-regulate storage such that all Ontario customers are provided with cost-based storage. 368 This re-regulation of intra-provincial storage at cost-based rates would bring consistency to the fact that Union provides cost-based storage services to some Ontario utilities such as NRG and Kitchener. However, in the event that the Board does not want to reconsider cost-based storage and is of the view that the RP-1999-0017 proceeding and the recent approval of the storage contract between Kitchener and Union in the RP-2000-2204 -- sorry, between Kingston and Union in the RP-2004-0141/EB2004-0221 has already established a principle of moving to market-based rates for intra-provincial storage and specifically for renewal of M12 contracts. 369 VECC is of the view that Enbridge's negotiated contract in the long run is likely to be in the best interests of ratepayers when considering the fact that this negotiated contract is deemed to be at a better price than the market. If we look at our book of materials, tab 4, page 15-1, that sets out the material that Mr. Brennan went over in his examination associated with the costs and the estimated difference between a market-based contract. 370 In addition, according to the Enbridge witness, it is his expectation that if the contract was to be renegotiated for April 2006, the market price of storage is likely to increase. And that's found in our tab of materials at page 13, which is transcript volume 2, paragraphs 1428-1429. 371 Further, it is likely that the 20 Bcf storage contract to be renegotiated for April 2006 will also have to be with Union, given that Enbridge is tied to the transportation contracts associated with this storage service. In examination by Ms. Aitken, Mr. Brennan confirmed that there are no conditions that allow the company to waive those two transportation contracts. And that's, once again, found in our book of materials, tab 4, page 13, transcript volume 2, at paragraphs 234 to 236. 372 Now, given Enbridge's contractual transportation commitments with Union, VECC has concerns that in April 2006 Enbridge's negotiation powers for the 20 Bcf of storage may be somewhat reduced relative to the contract they have currently negotiated whereby Union must recognize to some extent Enbridge's contractual right to the March 2006 expiry date. 373 Furthermore, VECC is of the view that Union is likely to have provided Enbridge with a fair and reasonable storage contract in this negotiated deal. The reasons for this are largely self-serving from Union's shareholder perspective since the contract is retroactive to April 2004, which in turn means an opportunity of obtaining higher and additional S&T revenues for the shareholder. 374 Clearly with Union's knowledge of this storage contract expiry date dispute, Union, in its RP-2003-0060 application, did not forecast the renewal of the Enbridge storage contract from cost-based rates to market-based rates. Thus the Union S&T forecast embedded in rates for 2004 does not assume any additional revenues from the market-based Enbridge contract. 375 VECC points out that the end result from the Board's approval of this storage contract and market prices is a bonus with the Union shareholders of 25 percent of the revenues in excess of the cost-based rates. There's clearly an incentive for Union to provide Enbridge a long-term storage contract that is slightly less than the market price in order to get this additional revenue for its shareholder. So we have additional sort of support for the prospect -- for the idea that this contract has been -- represents a good deal for the ratepayers in the event that the Board does not wish to revisit the issue of cost-based storage. 376 VECC notes that following April 2006, Union's shareholder will benefit by no more than 10 percent of the excess over cost-based revenues, since Union's intervenors and the Board will be aware of the price negotiation between Enbridge and Union for the storage service, and will build the effectiveness into the 2006 Union S&T forecast. In the result, Union's ratepayers would be allocated 90 percent of the benefit, and Union's shareholders, 10 percent. 377 Now, with respect to the term of the new storage service, VECC does not have any specific concerns with the ten-year term, since the 20 Bcf of storage contract is necessary to meet current customer needs and likely the future needs of EGD's franchise area as Enbridge customer base is predominantly composed of heat-sensitive residential customers and is expected to keep growing. 378 However, VECC does not agree that EGD's 2005 ratepayers should be paying rates in excess of cost-based rates to provide a benefit for future customers, as illustrated in Exhibit J.1.3. And that is not in our book of materials. 379 From cross-examination of the company witnesses, it is clear that 2005 ratepayers should only pay the cost -- should only pay the cost-based rates for storage, since the existing storage contract that is in dispute should legally expire in accordance with the original contract in March 2006. And that can be seen in our book of materials at tab 4, page 14, and it's found in transcript volume 2, paragraph 1353. 380 Given our position, our submission is that the appropriate regulatory treatment of the 2004-2005 storage costs, based on the new contract, in excess of the storage rate -- in excess of the cost-based rates incurred in fiscal 2005, is to defer these as an item in the transportation and storage deferral account and recover the costs by clearing to ratepayers in the subsequent two fiscal years, given that on April 2006, market-based -- market-priced storage would become necessary, in any event. 381 Furthermore, the two-year recovery of the excess to cost-based rates is justified by the analysis which indicates a crossover between the negotiated price contracts versus the market-based contracts occurring after the 2007 fiscal year. And that can be seen at tab 4 of our book of materials, page 15.1, Exhibit A3, tab 2, schedule 5, attachment column 3, in the Union exhibit. So if you look down to column 3, on our page 15.1, that is illustrated in terms of the crossover. 382 MS. NOWINA: Mr. Janigan, before you go on much further, I just need to understand a little bit better what you're suggesting with the deferral account. So can you go back to that point of the deferral account, what costs you've recorded in there, and which scenario we're looking at? So will Enbridge have entered into the contract at market rates for that period; and if so, what's going into the deferral account? 383 MR. JANIGAN: What's going in is the excess between -- for the 2004 and 2005 over cost-based rates that would be paid out over the two-year period subsequent. 384 MS. NOWINA: Okay, I understand. Thank you. 385 MR. JANIGAN: Column 1 gives that figure. And that concludes my submissions on the subject of the storage contract. 386 MR. BETTS: Thank you. Please proceed. 387 MR. JANIGAN: Thank you. My next topic is risk management, and in particular, issue 5.2, the RiskAdvisory report and Enbridge's response to the RiskAdvisory report. And the background and other references are found at tab 5 of our book of references, which is Exhibit 15.3. 388 Now if you turn up, in our book of references, tab 5, page 16, it has an excerpt from transcript volume 2, paragraph 501, the examination-in-chief of the Enbridge witnesses, that Enbridge is seeking in this proceeding with respect to risk management to implement the recommendations identified in the evidence at table 1 of Exhibit 1, tab 1, schedule 16. 389 And in my cross-examination of the company witnesses, it was elicited that Enbridge is not seeking to implement any of the changes associated with table 2 of Exhibit 1, tab 1, schedule 16, and that the company will address those changes as part of the 2006 rates case. And the reference for that is found at my book of materials, tab 5, page 16, which is transcript volume 2, paragraph 609. 390 Accordingly, VECC submits that the Board should only provide a finding in this proceeding related to the items identified in table 1. Enbridge should, in the 2006 rates proceeding, seek further approval for implementation of the issues outlined in table 2. VECC submits that the Board should make it clear that it does not provide any blanket approval for all of the RiskAdvisory report recommendations in this proceeding, as that could be construed to include the recommendations outlined in table 2. 391 Now, with respect to the specific relief Enbridge is seeking in this proceeding, as identified in table 1 of Exhibit 1, tab 1, schedule 16, VECC does not support the proposals to change the risk-management objective or to eliminate the 10 percent criteria on the hedgable volume restrictions. Furthermore, VECC is of the view that the relief sought to hedge forward for 12 months, as opposed to being restricted to the term of the fiscal year, should not also be granted at this time. 392 It is VECC's view that the Board should require that complete information regarding the operational impact be submitted and reviewed, either in the subsequent QRAM proceeding or in the 2006 rates proceeding before considering the request to hedge-forward for 12 months. 393 Now, first turning to the reasons why VECC is of the view that the current risk-management objective should not be altered. The objective is to maintain a system gas supply commodity portfolio that contains a proportion of floating price supply that's sufficient to provide an opportunity for market customers to obtain the benefits of market-based prices while limiting gas supply volatility and avoiding unacceptable price increases. 394 One significant reason why the objective of EGD's risk-management program should not be altered is that it is congruent with the Board's approval of the objective for Union Gas in the RP-2003-0063 decision, with reasons. In that proceeding, Mr. Snell, who was Union Gas's expert witness, noted: 395 "Risk management is clearly a balance between price stability and the need to purchase supply at levels that are as low as humanly possible." 396 And I've included that reference in our tab 4, page 16, and it is the evidence of Mr. Snell at transcript 1, paragraph 218, and that was from the RP-2003-0063 proceeding. 397 VECC notes that the Board in that proceeding was made aware that the redefined objective of the risk-management program for Union would accomplish more than merely price stability. In effect, the Board approved a risk-management objective that would provide value to ratepayers by purchasing system gas supply at a price as low as humanly possible, as a means to justify the continuation of risk management. 398 VECC supported that change to the Union objective in that proceeding, since it is, in our view, important to address the regulatory rate-making goal of ensuring the lowest cost achievable for ratepayers by way of the company's objectives underpinning risk management. 399 In this current Enbridge proceeding, the company is proposing to alter the objective that has been operating since August of 2001. Once again, if you look at our book of references, tab 4, pages 16 and 17, noted in transcript volume 2, paragraph 553 and 554, it contains the information concerning the length of time that this has been in operation. 400 The reason the company cites for seeking to alter the current risk-management objective is to be consistent to the historical Board decision EBRO-487. That's found at Exhibit I, tab 16, schedule 44, which is, in effect, a decision dating back to November 15, 1995. VECC is of the view that the relevance of the historical objectives set in 1995 is a less appropriate guide for this Board to rely upon than the more recent risk-management objective that's been in effect since 2001. 401 Clearly, much has changed since 1995. In particular, customers are concerned with a reduction in their total bill, as confirmed by Mr. Brennan in cross-examination. Furthermore, in cross-examination, Mr. Simard recognized the proposed change to the objective was not based on discussions with stakeholders, nor was it based on a review of the currently approved Union Gas risk-management program. 402 Given customers' concerns with having the lowest possible bill possible, it is imperative that the Board recognize that the risk-management program should attempt to provide customers with more than just price stability. It is at best uncertain from the cross-examination of the company's witnesses that if the Board were to adopt the changes as proposed, customers will not be given the opportunity of generating the best price or value from the risk-management program beyond reduced price volatility. 403 Now, in addition to not supporting the proposal for changing the risk-management objective, VECC also does not support the change to eliminate the 10 percent volume threshold for allowable hedgable volumes. VECC is of the view that elimination of the 10 percent volume threshold will change the way Enbridge currently carries out -- or may potentially change the way Enbridge currently carries out its risk-management program and it will allow the possibility of hedging all its hedgable volumes in one given day. 404 In his evidence, Mr. Simard clearly notes that one of the rationales for eliminating the 10 percent threshold is to avoid delays associated with the fact that hedges cannot be executed until the existing 10 percent tranche is hedged. In effect, the proposed elimination will allow for an acceleration of the implementation of a requisite hedge position, as noted in the cross-examination of Mr. Simard which appears in our book of materials at tab 4, page 17, and is in transcript volume 2, paragraphs 639-641. 405 However, the current methodology has the effect of averaging into the market, which was also clarified by Mr. Simard in cross-examination. The merits associated with the averaging into a position is viewed to be more prudent, and possibly more attractive, as noted by the expert witness, Mr. Simard. And that's once again found in our tab 4 of our book of materials, page 17, transcript volume 2, paragraph 646. 406 VECC is of the view the Board should not eliminate the 10 percent volume threshold, as there is a clear rationale and merit underlying the accomplish establishment of the 10 percent threshold in the existing methodology. However, VECC does support Enbridge's proposal to narrow the execution window to two days for AECO transactions and three days for the Chicago transactions, from the ten-day implementation period currently allowable by policy. 407 VECC is of the view that by approving a shorter execution window of two to three days, this reduces the concern for lost opportunity, as the time associated with carrying out a hedge will be quicker, allowing for additional hedges to be implemented in relatively short order. 408 Now, with respect to the issue of Enbridge seeking approval to hedge out for 12 months forward, as opposed to only within the fiscal year, VECC is concerned that the operational changes associated with the QRAM have not been completely identified or addressed in this proceeding. However, the company continues to seek approval for this change without full information available to the Board or intervenors. And we believe that lack of clarity surrounding the operational changes is highlighted in the cross-examination of Mr. Brennan by Ms. Aitken. And that's found at our book of references, tab 4, page 17, volume 2, paragraphs 816-822. 409 VECC recognizes that Union Gas received approval in the RP-2003-0063 decision with reasons to hedge out beyond the fiscal year. However, in that proceeding there were no operational changes or issues surrounding such a change, given that Union's QRAM method allows for the PGVA to be cleared on a 12-month-forward basis. In the Union proceeding, VECC supported the hedging period beyond the fiscal year. However, in this proceeding, VECC is hesitant to lend its support for an increase in the hedging period beyond 12 months without full information on this issue. Accordingly, VECC suggests that the Board defer this issue either to a subsequent QRAM proceeding or to the 2006 rates proceeding, when the company will address the operational issues surrounding the implementation of the risk-management change. 410 With respect to the RiskAdvisory report recommendation of documenting incidents of discretion, which is recommendation 3 in that report, VECC supports this increased accountability and documentation. Furthermore, VECC is of the view that the Board should require the company to file, in each rate case, the documentation associated with when discretion is used, as agreed to by Mr. Pleckaitis during his cross-examination. And that's found at the book of references, our book of references, page 18 and is in transcript volume 2, paragraphs 626 to 630. 411 In summary, with respect to the issue of risk management, VECC is of the view that the Board should not approve the substantive changes to the current risk-management -- Enbridge risk-management program at this time that we have outlined. We agree with the submissions of Ms. Aitken, in her cross-examination of Mr. Simard, that the existing system does not appear to be in a distressed state. 412 VECC is of the hope that the Natural Gas Forum will address the issue of benefits to customers associated with risk management by an LDC. 413 The Board noted, in its RP-2003-0063 decision with reasons, a need for such a review via a policy forum. I'm quoting directly: 414 "While the Board does not accept the arguments raised by CME and Energy Probe that Union's commodity risk-management program is without benefit, it does agree that such benefits are difficult to measure The Board believes that such issues are better studied in broader policy forums." 415 Accordingly, with the Natural Gas Forum underway, VECC submits that no substantive changes to the existing risk-management program, such as a change to the risk-management objective and the elimination of the 10 percent volume threshold, should be approved by the Board at this juncture. 416 Those are my submissions on risk management. 417 MR. BETTS: No questions on that issue either, Mr. Janigan. 418 Mr. Janigan, we're approaching 1:00 and I don't want to interrupt your submissions on a specific issue. Is there one that you could do in 10 to 20 minutes, or is -- 419 MR. JANIGAN: Oh, absolutely. Yes. Demand-side management I think we can do quite quickly, Mr. Chairman. 420 MR. BETTS: Let's proceed with that. We'll break after that for lunch. 421 MR. JANIGAN: And the background to this issue is found at tab 6, at page 20 of our book of references, and all DSM issues were settled with VECC's agreement, for the test year 2005. 422 We should just comment briefly on the proposal by Pollution Probe, who, having agreed with the basic test year DSM program budget and target, have now proposed a new initiative in the form of a high-efficiency boiler program. 423 We'd like the Board to understand that we are not opposed in principle to this boiler program since it has the potential to benefit low-income social housing agencies, schools, co-ops, et cetera. However, in the context of this particular rates case and in the context of the procedures and rules that we live by, this proposal is too late in the sense of coming after the negotiations respecting the 2005 program and budget, and too early in the sense that the company has not researched, analyzed and developed the program. 424 Accordingly, our view is that when the program has been developed and the budget allocated, it should be implemented, and we would be prepared to support a sustainable and well thought out program. We think that this will be several months, and practicality dictates that it may be part of a new multi-year DSM plan starting in fiscal 2006. So we, in no way, wish to have our position on this construed to be against a boiler program. 425 My other submissions are related to the treatment of DSM in the stub period, and if the Board order in this proceeding includes rates for the period October the 1st, 2005 to December 31st, 2005. 426 The two main issues are extension of issues 10.1 and 10.2 for the test year; first being the plan for the stub period, including the O&M budget and volume target, and the second, the treatment of the SSM and the LRAM for the stub period. 427 VECC agrees with the company proposal filed at Exhibit A7, tab 1, schedule 1, appendix 1, which is also in our book of materials at tab 6, page 21.1, in respect of a pro rata budget and volume target based on 25 percent of the test year amounts. We also agree with pro rata treatment of the lost revenue adjustment mechanism, LRAM, being continued to cover the stub period volumes. 428 However, VECC disagrees with the company proposal in respect of the treatment of the shared savings mechanism for the stub period. The company proposal is at paragraph 9 of the evidence, and an extract is included at tab 6, page 21 of our book of references. 429 VECC submits that the company proposal on the SSM, which is in three parts, is overly complex and contrary to the pro rata approach used to scale the 2005 test year program parameters to cover 15 months for budget, volumes, LRAM. 430 In our view, the most straightforward approach is to calculate the SSM based on the total aggregate volumes for the 15-month period. The company's arguments are that it may be difficult to earn a full SSM over this period. This prompts VECC to respond that, first, the stub period issue is of the company's own making; and second, any other proposal is more complex and subject to gaming, which the company denies, or other expected outcome that may disadvantage ratepayers or lead to disputes that the Board may be called on to arbitrate. 431 VECC, accordingly, urges the Board to order EGD to adopt a 15 -- which is a 12 plus 3 -- -month SSM calculation as per the first bullet of paragraph 9, which appears at Exhibit A7, tab 1, schedule 1, appendix 1, which is also at page 21 of our book of materials. 432 And that would conclude our submissions with respect to the issues of DSM. 433 MR. BETTS: Again, we have no questions on that particular issue, Mr. Janigan. Is it an appropriate time to break for lunch? 434 MR. JANIGAN: It would be, Mr. Chair. 435 MR. BETTS: Then we will break until 2 p.m., and we will return with submissions from yourself, Mr. Janigan. 436 Can I ask parties to discuss, either with Mr. Schuch or Ms. Lea, their expectation on how much time they will need for their submissions so that the Board Panel can consider that when we return, in order to be able to plan appropriately and get all of them in in an appropriate manner. 437 So give that some thought during your lunch break and we will discuss that when we return. Thank you. We'll adjourn until 2 p.m. 438 --- Luncheon recess taken at 12:58 p.m. 439 --- On resuming at 2:03 p.m. 440 PROCEDURAL MATTERS: 441 MR. BETTS: Thank you, everybody. Please be seated. Thank you, everybody. 442 Mr. Schuch gave me some estimates provided by the remaining intervenors of their time expectation for arguments. And what I have in front of me is Mr. Janigan, approximately an hour. Ms. Aitken, approximately an hour. 443 MS. AITKEN: At most, yes. Thank you. 444 MR. BETTS: Ms. DeMarco, two hours. 445 MS. DeMARCO: I'm in a unique position in that I have three separate arguments to make on behalf of three different clients, or client groups. So I could probably do two of the three in fairly short order, but the third, the transactional services final argument on behalf of CEED, will be a chunk of time. At least an hour, an hour and a half. 446 MR. BETTS: And we certainly don't want to limit you at this point. So just a fair estimate of how long you would need to represent all your clients would be fine. And is two hours a fair estimate or is that pressing you? 447 MS. DeMARCO: I think that would probably be fair. I was just having some preliminary discussions with Ms. Lea, and my preference, if it's acceptable to the Board, Mr. Chair, would be to keep the final argument together on behalf of CEED, and do that tomorrow. And if possible or whatever is the convenience of the Board, do the other two arguments around your schedule. 448 MR. BETTS: Right. And that's where I was going next, to see if you might be available tomorrow afternoon. 449 MS. DeMARCO: Yes. 450 MR. BETTS: You are? 451 MS. DeMARCO: I believe I am, and if not, I will be. 452 MR. BETTS: Okay. That's excellent. Then we feel as you do, that it would be more appropriate to allow you to go right through your arguments without an interruption. So at this point we're leaning towards bringing you back tomorrow afternoon, with no expectation of hearing from you today, by the way, to bring you back tomorrow afternoon to hear your argument or submissions in full. So, if that would work, we'd be looking at probably 1 o'clock tomorrow afternoon. 453 MS. DeMARCO: That's preferable to me, Mr. Chair. And if that's the case, I wonder if I might ask the Board if I might take my leave at this point. 454 MR. BETTS: Yes. That's fine. And we will see you tomorrow afternoon at 1 o'clock. 455 MS. DeMARCO: Sounds great. Thank you. 456 MR. BETTS: Okay. And I see Ms. Jackson is not here, but is Union represented? 457 MR. LAFORET: Yes, Mr. Chair. My name is Jim Laforet with Union Gas. We're expecting that we'll be approximately 15 minutes to put forward our argument, and we're hoping that we'd be able to follow Ms. Aitken at the end of today. 458 MR. BETTS: Then we will aim that way. 459 We are somewhat constrained today. So you are to some extent -- depending on how the two previous submissions go, will determine whether you are able to deliver yours today. But we'll see how that goes, and we're prepared to sit until about 4:45, at which point we will have to adjourn. 460 MR. LAFORET: Okay. That will be appreciated. Thank you. 461 MR. BETTS: And if that doesn't work, we would invite you back tomorrow afternoon with Ms. DeMarco. 462 MR. LAFORET: Okay. Thank you. 463 MR. BETTS: So I've probably taken up too much time already with that but it's been helpful to us. So, Mr. Janigan, are you ready to proceed? 464 MR. JANIGAN: Yes, I am, Mr. Chair. 465 MR. BETTS: Please do. 466 CONTINUED SUBMISSIONS BY MR. JANIGAN: 467 MR. JANIGAN: I'd like to deal with issue 11.1, the 2005 class action suit deferral account, and once again, the background and other references are at tab 7 in our book of references. 468 The company has proposed establishment of a 2005 CASDA for the test year to record costs incurred in defending the late-payment penalty litigation, otherwise known as the Garland case, in the 2005 test year, including any judgment against the company. 469 Now, it's important to note that this issue was scoped in the settlement proposal in the context of two alternatives being proposed to the Board. They are, number 1, that the Board establish a funded generic Board proceeding to allow full intervenor participation to consider whether court-ordered repayment of late penalty payments -- late-payment penalties by Ontario gas and electric utilities are properly recoverable in rates and provide a direction through that forum. And, number 2, in the absence of direction from the Board before the conclusion of this proceeding, a ruling on whether the Board accepts the company's proposal to establish a 2005 CSDA and the parameters of that account. 470 The cost components the company seeks to record in the CASDA fall into several categories: The legal costs of both the company and the plaintiff, the costs for the assistance of expert advisors and the gathering and analysis of its extensive historic billing information, the record of any amount of judgment against it in this manner, in this account, and the inclusion of allowances for rebates resulting from the judgment is really the core of this particular issue. 471 Counsel for the plaintiff has indicated, in the media, that they are of the belief that this amount will be in the order of $75 to $100 million. However, the court will determine the value of any judgment that's ultimately to be paid by the company. 472 VECC agrees that the scope of the 2005 CASDA should include recording legal and consultants' costs related to and arising directly from the court action. VECC disagrees that the company should be allowed to record any judgment-related customer-rebate costs in the 2005 CASDA for several reasons: The account was set up for the purpose of recording legal and other costs related to the late-payment suit, not the judgment. Secondly, the matter of who bears responsibility for costs arising from the late-payment suit and related judgment should preferably be considered by the Board in a generic hearing. And thirdly, the timing and quantum of judgment-related rebate costs is uncertain and may take months or even years to clarify and implement. 473 VECC notes that Union has applied to the Board for an accounting order to establish a deferral account to record the costs Union incurs in defending itself in this litigation, including any judgment against Union in this matter. Union's application was filed with the Board on June 22nd of this year, docket number RP-2003-0063/EB-2004-0386. 474 VECC's position is that the Board should defer its decision on whether to allow the company to record customer rebate costs related to the judgment. 475 The reasons I have set out are congruent with the statement that you made, Mr. Chair, at transcript volume 5, paragraph 926, that: 476 "This Panel cannot confirm that the Board will undertake a generic proceeding dealing with utility late-payment penalties. In the absence of a direction for a generic proceeding, the parties have suggested that the issue is, and I quote: 477 'Should the Board establish a 2005 CASDA and if so, what costs should be included therein?' 478 "While the Panel agrees to consider whether to approve establishment of the requested deferral account, it will not be determining whether any of the amounts to be recorded in the deferral account would eventually be recovered from ratepayers. Furthermore, the Panel expects parties to restrict their treatment of the matter to the narrow issue the Panel has to decide. The Panel presumes any parties wanting to deal with the question of what costs should be included will be directing their examination to the type of costs to be included. It is likely that a detailed discussion of forecast amounts will be useful to the Board Panel." 479 Now, VECC can't help but note what appears to be a reverse of the general onus of proof, which was set out in the company's argument in chief by Ms. Persad, and particularly, if you would note that on tab 7 of our book of references, at page 22, there is a reference to transcript volume 13, at paragraph 256, where Ms. Persad indicated: 480 "In the absence of a thorough examination of the repayment and recovery issues, the Board simply does not have the information or evidence before it in this case to base any decision denying the company's request for establishing the 2005 CASDA on the eligibility criterion." 481 We would respectfully submit that the onus of proof for the establishment of this lies directly upon the company. And, in our view, EGD has not yet met that burden. The Board has sufficient grounds to deny the company's request to extend the scope of the 2005 CASDA. 482 VECC recommends that the company be directed to apply for either a new deferral account or an extension of the 2005 CASDA when information on the costs of implementation of the judgment is available. At that time, a more extensive review of the cost responsibility of ratepayers and shareholders can be conducted. This review could be preceded and informed by a generic proceeding on the issues. 483 That concludes my comments on the CASDA. 484 MR. BETTS: The Board Panel has no questions on that. 485 MR. JANIGAN: Thank you, Mr. Chair. 486 The next issue is the issue of number 12, deferred taxes, which is the equivalent of the Hatfield and McCoy feud in regulatory terms, spanning some four to five proceedings, and the Enbridge Gas Distribution Inc.'s proposal to recover the after-tax amount of 23.9 million over a two-year period, 18.4 million pretax in 2005. 487 Now, the background and other references are under tab 8 of our book of authorities at page 24. 488 the issue in particular relates to the company's claim that it was authorized by the Board in the EBO 179-14/15 decision to recover costs related to a claimed $15 million deferred tax liability related to utility rental assets transferred to an affiliate. 489 In the Board's decision, which I believe is excerpted in our -- I think it's right here, on page 24, at the middle of the page, it indicates precisely, or it indicates at least the terms upon which, in the RP-2002-0135 decision, Enbridge was entitled to recover from the notional utility account an amount after taxes equal to the deferred taxes that became payable between October 7th, 1999, and May 7th, 2002. 490 Now, Enbridge has determined that the amount of the deferred taxes that became payable in that period, October 7, 1999 and May 7, 2002, to be 23.874 million. In VECC's view, company Exhibit K.7.1 is a key piece of evidence and we have included this in our book of references under tab 8, at pages 32-12 and -13. 491 Page 32-13 shows that from October 1999 to May 2002, Enbridge Services Inc., 3696669 Canada Inc., otherwise known as Rentco, operated the former utility water heater rental business based on the assets transferred from EGD in October 1999. The deferred taxes that became payable on the transferred assets were 23.9 million, and that figure is found in evidence A5, tab 5, schedule S1, schedule 1, and business taxes were 24.4 million, for a total of 48.3 million. And that figure as well can be found on page 34-13 at the top right-hand portion of the page. 492 However, Rentco also acquired additional rental assets and operated these together with the transferred utility assets as a single pool. The CCA tax shield from the new assets was 37.4 million so that the net cash income tax paid by Rentco was 48.3, less 38.7, for 10.9 million. 493 In addition, ESI received a deferred tax credit of 5.2 million on new rental assets, which is shown about three-quarters of the way down the page, and an installation tax credit of 13.7 million, shown underneath that, which offsets ESI business taxes payable of 21.3 million for net cash tax paid by ESI of 2.4 million. 494 Now, the issue seems clearer to a non-accountant, anyway, if considered from a business perspective. If you turn over the page and look at 32-12, Enbridge had several options, as a result of the EBO 179-14/15 decision. According to the company's evidence, it evaluated these options and decided to operate the water heater rental business in ESI as a going concern, with water heater assets and customer lists that were transferred from the utility. And that's noted also in our tab of materials at page 28 of the tab of materials, reflected at transcript volume 9, paragraph 378. 495 ESI then increased rents by over 19 percent, and also rented new and replacement water heaters to EGDI's customers. Then, in December 1999, EI decided to segregate the old utility rental assets into Rentco and lease them back to ESI. However, I think it is significant that ESI retained control of the customer lists and the rental accounts. 496 So during the period of 1999 to 2002, ESI and Rentco made significant operating net income generating significant after-tax profits. The business was sold in 2002 to Centrica for a gross consideration of over 1 billion and an accounting net gain of 240 million. 497 Now, one new and highly significant fact that emerged from this proceeding is that Rentco/ESI received a tax credit of 42.8 million relating to the old utility rental assets as a result of a tax reassessment. The evidence is clear that, rather than applying it in whole or in part to reducing the $50 million liability in the notional utility account, Rentco/ESI used this refund to reduce the overall accounting deferred taxes on the books of ESI/Rentco, which later on decreased the net tax liability and increased the consideration received from the sale of the business. 498 VECC submits that this tax refund should have been applied pro rata to the total accounting deferred tax liability of Rentco/ESI, and reduce the $50 million claim against ratepayers. 499 MR. BETTS: Mr. Janigan, I didn't want to interrupt, but there's something that's going to bother me unless I ask this question. 500 You've stated that the 42.8 million went to ESI and Rentco. Now, can you -- I'm not sure that that was my understanding, and I'd like to make certain that my understanding is correct. 501 MR. JANIGAN: Well, my understanding is that Rentco and ESI received a tax credit of 42.8 million that related to the old utility rental assets as a result of a tax reassessment. 502 MR. BETTS: Okay. We'll perhaps -- 503 MR. JANIGAN: If I'm incorrect on that point, I apologize. 504 MR. BETTS: My understanding was that it went -- that went to -- that was handled before the assets were transferred to ESI. 505 MR. SOMMERVILLE: I'm just looking at the transcript reference that you've provided in your materials. 506 MR. JANIGAN: Mm-hm. 507 MR. SOMMERVILLE: At tab 8, and the transcript volume 8, paragraph 257. Now, it's not explicit on this point. I think there are, perhaps, better references, Mr. Janigan. But my impression was that the 42.8 million went to the utility, and was used to increase the 126 million to the ultimate 168, and that's how we ended up with 168 million. 508 MR. JANIGAN: I believe that is correct, Mr. Chairman, and I certainly accept that. 509 MR. BETTS: Thank you. 510 MR. JANIGAN: And thank you for that correction. 511 MR. BETTS: Sorry for the interruption. I wanted to make sure we had that straight. Please proceed. 512 MR. JANIGAN: It's appreciated. 513 Now, VECC notes at EBO 179-14/15, the Board determined that the deferred tax liability was to be shared between the shareholder and ratepayers and placed a cap on the ratepayers' portion at $50 million, which is why we are here today arguing this matter. 514 We believe there are several important questions to be asked. Why do ratepayers remain liable for deferred taxes related to the original old utility assets, given the fact that a profitable business was founded on the former utility assets and customer lists, and operated as a going concern? 515 Secondly, why was the consecration of old utility assets continued despite operating the rental business as a going concern? Normally the tax shield from the new rental assets would be used to shelter the deferred tax related to the old utility assets. In fact, the evidence at K.7.1 demonstrates that in practice that this was done, but it was not accounted for that way because EGD had been told to book a $50 million regulatory account receivable on its books. 516 Thirdly, why were customer lists and net income, basically the profits related to the old rental assets, why were they not segregated and reported separately? 517 Now, as we know, the combined assets and customer lists were sold to Centrica for a consideration of over $1 billion and a net profit of $230 million. In VECC's view, these larger questions remain, despite the narrowing of the issues as a result of the Board's 2002-0135 decision. 518 Now, if we could return to the chart at 32-12 in our book, and it indicates in this chart, under the December '99 to May 6th rental assets, it shows: What is the real issue of who pays and who benefits? 519 If the boxes 2000 to 2002, which is shown about three-quarters down the page, the new non-utility rental assets were combined as they were from a business operations perspective, then there would not likely be any net deferred tax liability claim against ratepayer. In other words, they were combined with the Rentco assets, the utility rental assets were combined with the new non-utility rental assets, which they were from an operational standpoint, there would not likely be any net deferred tax liability claim. 520 VECC submits that the only logical conclusion is that EGD and EI managed the tax situation related to the old rental program assets in order to maximize the recovery of the $50 million regulatory account receivable it booked under the notional utility account, rather than taking a normal tax planning account to the integrated ESI/Rentco rental business that was operated as a single profitable business. 521 Now, once again, we hesitate in informing the Board what we think the Board said, and we don't like to be in this position, but we seem to have been in it for the last three proceedings. What we believe is what was intended to be a shield was wielded like a sword by the company to maximize their take, under this particular provision. And, as a result of the Board's finding in RP-2003-0135 decision that EGD is eligible to recover up to the amount of the deferred taxes that became due and payable between October the 7th, 1999, and May 7th, 2002, the company has taken a 26.2 million regulatory asset write-down, as can be seen from the 2004 bridge year financial schedules. 522 VECC is of the view that EGD's claim is not supported by supported by the evidence, and secondly, EGD and its affiliates appear to have used tax planning in an aggressive fashion to attempt to maximize recovery of the national -- of the notional utility account, regulatory account receivable. 523 VECC also notes that residential ratepayers will bear the brunt of any Board-authorized notional utility account recovery. And this is evident from our book of materials at tab 8, page 32-11, which is J9.3, the undertaking. It shows that rate 1 will bear a 65.7 percent recovery of this amount, basically, two thirds of the amount. Rate 1, of course, containing residential ratepayers for the most part. 524 The ratepayers that benefited from inclusion of rental asset costs and revenues in the utility operations and rates were customers of Consumers' Gas prior to 1999. In the intervening five-year period, the utility has grown by about 400,000 customers. This five-year period during which time this matter has been litigated and adjudicated. 525 In these circumstances, there would seem to arise questions of significant intergenerational inequity inherent in any of the notional utility account. The question that's before us is, should the new customers as well bear the cost consequences of actions taken more than five years ago? 526 And those are VECC's submissions with respect to the deferred tax. 527 MR. BETTS: Thank you, no further questions on that one. Please proceed. 528 MR. JANIGAN: The next topic is the change in the fiscal year-end, and issue 13.1 in particular, the proposal to change Enbridge Gas Distribution's year-end from September 30th to December 31st, 2005, and its implications. We have set out in tabs 9 and 10 of our book of references the appropriate background and other references that we will be referring to. 529 VECC submits that the rate-making implications and the appropriate regulatory treatment of this issue can only be clearly addressed by consideration of what the company is proposing in its two component parts. 530 The first is approval of a revenue requirement in rates for 2005 test year from October the 1st, 2005 to September the 30th, 2005. 531 Secondly is an indexing of rates as a proxy for a cost-of-service increase and an increase in the revenue requirement for the stub period. The answer to the appropriate regulatory treatment for the stub period must also be informed by the key fact that the company plans to apply for a new revenue requirement and rates for its new 12-month calendar year test year, 2006, to be effective January 1st, 2006. 532 Now, the company has applied for a recovery for fiscal 2005 revenue requirement of $2,899.6 million, and that's located at tab 10, page 40-5. And it's at line 21, column 2. 533 MR. BETTS: Sir, the reference was page 40-5, line? 534 MR. JANIGAN: I'm sorry. That would be at line 9. 535 MR. BETTS: Thank you. 536 MR. JANIGAN: And rates will have to be increased by 60.6 million to recover the revenue requirement over the period of October the 1st, 2004, to September the 30th, 2005. And this amount, of course, may change as a result of the Board's decision in the final order of this proceeding. 537 Now, the normal regulatory compact or protocol is that, once approved, rates stay in place until changed as a result of an application for an increased revenue requirement for a forward test year. For a utility with low growth and customer base, this may be some time. In this case, the company has also applied to index rates for the period October 1, 2005, to December 31, 2005, the so-called "stub period," rather than bring forward a complete set of cost-of-service presentations and revenues for the stub period. 538 Another regulatory principle is that for a test period, which is usually 12 months, admittedly, there should be a matching of costs, including cost of capital, and revenues. What the proposal to change the regulatory cycle of a seasonal business like that of EGD does, is create an isolated three-month test or stub period. And the onus is then placed upon the company to show whether costs and revenues should match over this rather unusual test period. 539 At tab 9, page 38-1 of our book of references, which consists of Exhibit J.10.2, it shows that rates approved so far for the settlement proposal for fiscal 2005 can result in a significant revenue sufficiency or small revenue deficiency over the stub period, depending on how the return on capital component of the revenue requirement is calculated. 540 So if we see in the different schedules that have been attached, the different cost of capital results or return on capital results will result in either a significant revenue sufficiency or small revenue deficiency, so that effectively the issue of the stub period has been narrowed to what is the appropriate rate of return on equity to apply. But the bigger context is, in effect, what is the overall treatment of the stub period that should apply for regulatory purposes? 541 And in thinking about this, there are three practical approaches that could address this. One is to treat the stub period as an isolated one-quarter of a year test period and determine the appropriate revenue requirement, including return on capital. Secondly is to treat the stub period as the fifth quarter of a 15-month, 2005 test period, going from October the 1st, 2004 to December 31st, 2005, and then set rates to recover the full 15-month revenue requirement. Thirdly would be to reject the proposed indexing of rates and approve rates only for the 2005 test year, a period up to September the 31st, 2005. Then the Board could require the company to research the stub year issue and make an application for a 2005 calendar year cost-of-service, the first nine months of which overlap with the approved revenue requirement for the 12-month fiscal 2005 test year. 542 Ms. Hare outlined this option during her examination on the company's motion, during the first days of this proceeding. 543 Now, VECC does not favour the latter approach because of the rate uncertainty and regulatory inefficiency that it creates. For either of the first two approaches, a proper estimate or forecast of costs of revenues for the period October the 1st to December the 31st, 2005 is required. 544 The projections in Undertakings J.10.1 and 10.2 are unfortunately late in the process and have not been tested in the cross-examination. 545 As I stated earlier, the evidence before the Board indicates that the amount of the stub period overrecovery of costs will also be influenced by the Board's final determination of unresolved issues with respect to EGD's 2005 test year revenue requirement. 546 As to the appropriate regulatory treatment of the October to December 2005 stub quarter, it's to be noted that in a normal EGD test year, any overearning or excess of revenues over costs that occurs by a result of a mismatch of revenues and costs in the first quarter is automatically carried forward to the next quarter, and so on. 547 If the revenue requirement and revenues from rates are set properly in a year, the result will be a zero sum gain over the four quarters of a test year. This is not the case here, in the circumstances of the company's proposal. 548 Overrecovery of the costs in the last quarter of 2005 will not be carried forward into the next quarter because, under the company's forward regulatory plan, the next quarter will be the first quarter of the new calendar year, 2006, with a whole new revenue requirement, including annualized cost of capital and rates set to recover that revenue requirement. 549 Accordingly, unless you have an explicit adjustment for the excess of revenues over costs in the last quarter of 2005, there's no mechanism in place like there is in an ordinary test year to ensure that the revenues and costs will match up over the course of the year. The new rates will be set to recover the new 2006 full-year revenue requirement. They will not be set to recover any overearning during that previous quarter. 550 Now, once EGD's 2005 revenue requirement and rates have been finalized, intervenors suggest that the practical way to measure the extent to which EGD's rates overrecover costs in the stub period is to determine the extent to which the ROE in the stub period exceeds one-quarter of the allowed ROE. 551 This way of measuring the cost overrecovery in the stub period is appropriate, because all amounts recovered in the rates in the stub period in excess of the costs incurred in the stub period, including the cost of debt capital for three months, are accounted for in equity earnings. 552 It's appropriate to note the sequence of events by which rates are set. We determine the revenue requirement, which includes the importation of a return on equity, then we determine what revenues the company will collect, then we set rates. 553 The first element is the setting of the revenue requirement, which includes the setting of the cost of equity. We don't do the reverse: Look at revenues in order to determine the cost of equity, which, in some respects, is what the company is urging upon you in this proceeding by urging the fact that it has to recover those revenues in the stub quarter. It's a bit like determining the -- taking a period of a hockey game out and saying that all those goals have to apply into a new game. 554 In this circumstance, if we have a stub period, the stub period return on equity has to be determined in the same fashion that the return on equity is determined in the context of a test year. In this case, it would be one-quarter of the return on equity allowed under the Board's formula. 555 MR. SOMMERVILLE: Mr. Janigan, isn't it true that, if the company decided in 2006 not to come in for new rates, that the 2005 rates would continue, by operational law, past September 30th of 2005? And that those rates would continue without amendment, ad infinitum, unless they were changed by some external agency, where the company brings an application or some other external agency. 556 How do we understand your argument in the context of that? It seems to me that, for your argument to be right, we have to be looking at the discontinuation of the company's business at the end of that stub period. And then we might say, Yes, there is a discontinuity here somewhere. 557 MR. JANIGAN: Well, a discontinuity may arise if there is a termination of the company's business at any given point in time. But if the rates simply continue, it all comes out in the wash; you're right. But in this circumstance, what we have is an anomalous period. You have a three-month period which is effectively part of a larger test-year period, or rates were set on the basis of a 12-month period. And incorporated into those rates was the idea that the sufficiency that was accumulated in that period would be diminished as the year rolled on. But we don't have that diminishment -- that diminution is not going to take place in this case. 558 MR. SOMMERVILLE: Isn't the only thing that we have a change in the reporting period? Isn't that the only -- isn't that the only change? We're really only talking about how the parent company reports the results or performance of the subsidiary. And that's the only stub element to this -- the gas coming into and out of storage doesn't recognize the stub period. The only thing that's the stub period is this change in reporting requirement occasioned by its relation to its parent. 559 MR. JANIGAN: Well, certainly if a different revenue requirement applies in 2006, then there will obviously be a change in circumstance. 560 But just looking at that three-month period, and that three-month period by virtue of the change has become sort of an orphan period, there's no matching of costs of revenues to generate the appropriate rate of return in that period of time. There is, if that's part of a -- if it's part of a larger 12-month period. But once it's segregated out, you either have to do your own little cost-of-service review or attach it to another period. It becomes an orphan. And the problem is, is that if you did, in the circumstances of the current rates applying for that period of time, you're going to get an overcollection of earnings that will not necessarily wend its way out in context of the New Year. Because the new year is going to be set on the revenues that are applicable over the course of the full year in 2006. 561 MR. SOMMERVILLE: Thank you. 562 MR. JANIGAN: By way of example, if you had a hypothetical that the company had requested to change its fiscal year in a fashion that created a stub period from April 1 to July 1, would the company have accepted that it should be allowed to earn a normal return for that period, which would be about a negative .4 percent, indicating that costs significantly exceed revenues? And we would suggest that it would not and that we would appropriately apply the costs and revenues to that period to get the rate of return. And by the way, that figure of .4 percent arises in the context of School Energy IR 158, page 2 of appendix A. 563 Now, I would suggest that in that particular context, it would be argued by the company that it was an unintended outcome of the change in fiscal year and that it should be allowed to earn one quarter of the allowed annual return of about 2.5 percent, due to the unusual circumstances before going into a new test year. And when we look at what the company has done in the schedule on page 5 of J.10.2, and that's referenced at our tab 9, page 38-5, its normal calculation of the cost of capital is to assign a one-quarter pro rata annual cost rate to the long and medium-term debt, short-term debt, and preference shares, but not assign a one-quarter of the 9.69 percent allowed annual return, but rather assign the cost rate of 4.057 percent that it feels it historically should earn in the first quarter of the fiscal year. 564 Now, the responses to Undertakings J.10.1 and 10.2 show the range of the stub period overrecovery values. Under cost-of-service regulation for the costs for the stub period, which is something that EGD requests, and for the 12 months and calendar year 2006 followed by the stub period, which EGD also will request, intervenors, with the exception now of Schools, take the position that the utility shareholder is not entitled to the stub period overrecovery amount. A stub period overrecovery adjustment, we would submit, is required. 565 Now, whether the stub period overrecovery adjustment is carried back to reduce 2005 test year rates or carried forward in a deferral account to be cleared when the Board determines EGD's 2006 test year revenue requirement are alternatives. The key point is that VECC and the rest of the intervenors, apart from Schools, believe that EGD's shareholder is not entitled to benefit from the extent to which EGD's proposed stub period rates overrecovered costs being incurred by EGD in the stub period. 566 Now, if the Board has concerns about the uncertainty created by the stub period issue and wants to ensure that rates are just and reasonable for both the 2005 test year and final stub quarter of calendar 2005, VECC suggests that protection of ratepayers and shareholders from unexpected outcomes should also be considered. This would require a post-facto audit of the results of the 15-month, 2004-2005 test period to ensure that rates up until the end of calendar 2005 do not either over or undercollect related relative to the approved cost-of-service. In either case, then, an adjustment would be made in 2006. 567 Now, unfortunately, the regulatory financial results will not be available until the second quarter of 2006, and the company's plan is for new rates to be in place in January 2006. Accordingly, a 2005 stub period deferral account would need to be authorized in the Board's rate order. 568 Now, I'd like to address the second part of EGD's stub year proposal, which is the proposal to increase rates in the period of October 1, 2005, to December 31, 2005, and the implications that arise from that. And we've provided in our book of reference at tab 10, page 39, some of the materials which we think are necessary for the full understanding of that. And we have already argued under issue 13.1 that the Board should reject the company's proposal for indexing rates commencing October 1, 2005. I'd like to expand on why, regardless of the Board's decision on the stub period overearnings issue, the company's proposal is inappropriate, and will not result in just and reasonable rates. 569 First, the company has acknowledged that indexing is not a superior way to go. If we look at page 39 of tab 10, transcript volume 10, paragraph 716. This includes the company's comments on this particular mechanism. 570 Secondly, the company has based its claim on estimates of certain increased costs for the stub period. For example, I point you to the response at page 40-1 of our reference book, a response to VECC IR 136, which sets out estimates of increased costs. It's then applied a factor of 90 percent of annual CPI. 571 We would submit that this is an approach that cannot be justified because the company has said it will seek to change rates three months later. Therefore, the application of one quarter of an annual inflationary factor for three months will result in annualized rates that may be too high and not be just and reasonable. 572 Now, why is indexing rates in this case wrong? 573 It is because that although in the stub period, costs may increase, so will revenues. And the company has ignored this key fact in making its request for indexing of rates. The company has ignored the question of what revenues will be generated from the rates approved for fiscal year 2005 to counteract increases in costs during the stub period. 574 Now, Mr. Chairman, at volume 13, transcript volume 13, paragraph 657, which is at page 39 of our book of materials, you ask Mr. Cass the same question. And to paraphrase, effectively, why don't revenues increase and offset increased costs? 575 Mr. Cass referenced VECC IR 137 on the cost side, and also referred you to Exhibit A9, tab 2, schedule 3. And I point out that A9, tab 3, schedule 3, has not been updated and is now Undertaking 10.2 that we should be looking at. And if we turn, then, to tab 9 in our reference book, and page 38-5, which is J.10.2, and at page 5 of J.10.2 -- and this, once again, is evidence that has not been subject to cross-examine cross-examination -- it shows at lines 13 and 14, that: 576 "Revenues from existing rates slightly exceed the revenue requirement with the normal return on equity." 577 MR. BETTS: Pause for a moment. Let's continue, Mr. Janigan. 578 MR. JANIGAN: I would note in the use of the term "normal", that normal is what they call normal at a return of 4.057. This illustrates again the problem with the stub period, without adjustment, by an inflationary index. The stub year rates EGD proposes may not be just and reasonable. 579 Secondly, if a formula which consists of one-quarter of the annual return on equity is applied, and we see that at page 38-6 of our book of materials, there is a forecast sufficiency in revenues over costs for the stub period. And in that circumstance, would rates be just and reasonable if indexing added another 4.5 million to that sufficiency? We think not. 580 I also note that the figures assume that EGD will recover the full 18.6 million from the notional utility account in the test year. Accordingly, VECC submits that the company has not demonstrated clearly that an increase in the revenue requirement and rates is required for the final quarter of calendar 2005. 581 The regulatory compact, as it were, is that, if the company wishes to change rates, it must first justify that such an increase is required. VECC urges the Board to reject any proposal that is not supported by a fully tested forecast of costs of revenues for the stub period. We submit that close scrutiny of the projections will show that there is no material revenue deficiency. 582 Now, in response to questions from Mr. Thompson about index rates in fiscal 2004, and that's found in our tab 9, page 37, and it's transcript volume 11 at paragraph 790 -- actually, 79, the company disclosed that it is forecasting a revenue sufficiency or overearning of 8.9 million. We suggest that this illustrates that indexing was a one-time expedient for 2004 -- I should say, a one-time experiment for 2004, an experiment which VECC opposed and should not be approved in this case. 583 Unfortunately, the only cost-of-service information the company has filed for the period beyond the 2005 test year is late, incomplete, and untested. VECC requests that the Board find that the company has not met the burden of proof that proposed index rates will be just and reasonable, and therefore the rates approved in the Board's rate order in this proceeding for fiscal 2005 should continue until changed by a Board order following a new application based on the 2006 forward test year. 584 That concludes my submissions on the change in the test year. 585 MR. BETTS: The Board Panel has no questions on that issue, Mr. Janigan. 586 MR. JANIGAN: Thank you, Mr. Chairman. 587 The next issue is the issue of rate design, first, at 15.1, the proposal to remove rate seasonality for all rate classes except rate 135. And as is noted in the ADR settlement, VECC supports the Enbridge proposal to remove the seasonality for all rate classes except 135. 588 In issue 15.2, the proposal to increase the monthly customer charge for rate 1 from $10 to 11.25, we have assembled at tab 11 of our book of references, page 41, some materials which we think is helpful in the discussion of this matter. 589 I should note at the outset that the settlement proposal indicates a partial settlement. If you look at the parties - and this is on page 41 - if you look at the parties to that proposal, neither CCC/CAC nor VECC, which represent the rate 1 customers, agree with the settlement. 590 What value is that partial settlement in the circumstances? The company claims that the change is revenue-neutral, and accordingly we ask, Why are they ignoring the opposition of the constituent groups that represent rate 1 customers? 591 According to Exhibit H1, tab 1, schedule 3, page 4 of the company's evidence, EGD is seeking Board approval in this proceeding to increase the fixed monthly charge to all residential customers which are rate 1 customers. The evidence states that the rationale for the increase in fixed monthly customer charge is to enhance the recovery from the current level of recovery of approximately 50 to 60 percent of customer-related costs. 592 Furthermore, the higher recovery of fixed costs from fixed charges is desirable because it reduces intraclass cross-subsidies. 593 VECC does not support an increase to the fixed monthly customer charge as proposed by Enbridge, even though, from the company's perspective, this is a revenue-neutral rate-design issue. The fixed monthly charge is to increase with a corresponding decline in the volumetric charge so the company will not generate additional revenues, and we are aware of that. 594 However, while the company is going to be held revenue-neutral, the individual customers within rate 1 are not going to be held revenue-neutral. The change to the fixed monthly customer charge will cause real bill increases for small-volume customers. The reason for a bill increase experienced by the low-volume user is due to the fact that customers with low volumes do not consume enough at the lower volumetric rate to offset the increase they will experience in the fixed monthly customer charge, as was clarified by Ms. Collier in cross-examination. 595 VECC's, of course, constituency is low-income customers; we would submit that such customers are overwhelmingly low-volume users. And we are concerned that this group of vulnerable energy customers may be, in effect, faced with a real rate increase, albeit a small one, due to the proposed rate-design change, which isn't revenue-neutral from their standpoint. 596 Ms. Giridhar does note in cross-examination that intuitively low-income customers would presumably live in smaller homes. And the experience overwhelmingly, we would suggest, from utilities is that low-income customers tend to be low-volume customers. 597 Accordingly, some of the most vulnerable energy consumers are likely to be within the range of customers that are going to be experiencing rate increases, while the high-volume customers are likely to be experiencing either rate decreases or being held revenue-neutral. 598 Enbridge claims that this change to the fixed monthly customer charge is necessary to enhance the recovery of fixed costs by a fixed charge, which in turn improves the intraclass cross-subsidization issue within the rate class. VECC would give more credence to this rationale if it was not -- if it was followed consistently in the other rate classes. 599 In cross-examination, Ms. Collier confirms that rate 6, rate 100, rate 115, rate 135, rate 145, rate 170, and rate 305 are all rate classes that have a lower rate of recovery of their fixed costs by way of a fixed monthly charge. That's found at volume 6, transcript volume 6, paragraph 506 to 514. 600 In the result, these rate classes, when compared to the residential rate classes, are not being held accountable from a cost-causality perspective within their own rate class. In fact, these rate classes have a lower percentage of recovery of fixed costs compared to rate 1, which indicates that these rate classes have a more pronounced issue of intraclass cross-subsidy occurring than that being displayed in rate 1. 601 Regardless of the greater issue of intraclass cross-subsidy in other rate classes, the company is not driven with the same degree of rigour to adhere to the principles of cost causality for other rate classes in the same manner that has been espoused for rate 1. 602 In cross-examination, it is clear that large rate class customers, in fact, incur a larger fixed costs for items such as meters. Meanwhile, the company has not addressed increasing the fixed cost-recovery levels, and maintained fixed cost-recovery levels substantially below the current 50 percent level for rate 1. 603 The varying degree of recovery of the fixed costs by way of a fixed charge is clearly inconsistent across the rate classes. The company may argue that these other rate classes shouldn't necessarily have a higher recovery rate for fixed monthly charges since the classes are not as homogenous in terms of customer-related equipment attached to a customer premise. 604 VECC questions the reasonableness of this argument when large industrial rate classes require customers to take volumes at a minimum level as part of the applicability requirements, thus eliminating the ability for customers with varying volumes to cause vastly different fixed costs. Now, this point is exclusive of rate 6. 605 Furthermore, the premise of rate design is to aggregate customers that have similar homogeneous characteristics into a single rate class. To now claim that a lower percentage recovery isn't applicable to other rate classes compared to rate 1, based on an argument of a lack of homogeneity of customers in a specific rate class, brings into question the reasonableness of Enbridge's basic rate design principles for each rate class. 606 The rationale for the lower percentage recovery of fixed costs for each rate class can only be explained by the use of judgment, as rate design is a balance of achieving goals that are unrelated to pure cost causality. Enbridge accepts the use of judgment in this proceeding as it proposes to eliminate rate seasonality, as it ignores the pure cost causality principle to balance the interests of reducing the administrative complexities associated with this rate design issue. 607 It's to be noted that the issue of customer charges and the necessity to pick up costs by way of a customer charge is largely a regulatory utility you concede. In the real world that we are trying to proxy, generally a business recovers such costs in the costs of the product, even for important services. So, in effect, we are dealing with, to some extent, the regulatory world and the hypothetical constructs that we use to try to recover costs. 608 VECC is of the view that this rate design proposal for increasing the fixed monthly charge is not reasonable, given the fact that this change -- is not reasonable, and one of the reasons why we have come to that conclusion is that the change is likely to be viewed by customers in a negative fashion and contrary to the established socially economical rates for residential customers. We note that the customer focus group report attached to VECC Interrogatory No. 17, and the copy of executive summary which is included in page 4-1 of this book, it was evident that customers were not receptive to changing the fixed monthly customer charge. 609 Furthermore, the customer focus group noted in its conclusions that the implementation of the proposed changes to the fixed customer charge carries many negative implications for Consumers' Gas, the precursor of Enbridge, and its customers and its regulators. 610 VECC submits that these real perceptions of customers that were summarized in it focus report should be taken into consideration. Furthermore, these perceptions should assist the Board in determining that further increases to the fixed monthly customer charge to residential customers are unnecessary, and are not reasonable as clearly pure cost allocation -- sorry -- are unnecessary, and are unreasonable as pure cost allocation should not be the determining factor for further rate design increases to the fixed monthly customer charge to residential customers. 611 Finally, if the Board feels that the company's arguments concerning the parity with Union Gas have merit, that a phase-in period over two to three years would be appropriate and would create less of a concern to low-and fixed-income, low-volume, rate 1 customers. 612 And those are my submissions on the rate design customer charge issue. The last -- I'm sorry. 613 MR. BETTS: One question I would like to put to you is, it seems to me that in your argument you've been differentiating between class 1 and others by discussing the percentage of their rate that's apportioned to the fixed charge, versus the volumetric. And you've implied that the percentage should remain the same. I think what I'm trying to say is you're suggesting to me, in your argument, that the fixed portion should vary with the amount of energy that a consumer uses, because if the percentage is a fixed amount, as one uses more, then that portion would increase in true dollars; is that not correct? 614 MR. JANIGAN: Well, no. I think I'll go back. My initial premise, is that, I guess, first of all, there is no magic or no right formula for the recovery of the customer-related costs. There is no magic number that has to be hit. And what we have done is attempted to use the examples of the other rate classes, and what is recovered by way of the customer-related costs in terms of the percentage from the customer charge itself. 615 So that, in rate 1, the idea that we are now becoming closer to the pure principles of cost allocation by moving from 50 to 60 percent is, in our view, mistaken. Because when we look at all the rest of the rate classes, there is a variety of different percentages that are recovered. And in this circumstance, the way in which we will move is to essentially, in a small fashion but in a fashion nonetheless, to effectively put the negative consequences on the smallest-volume users in that particular class where the customer charge is raised. We don't see the necessity, we don't see the magic in why we're going from 50 to 60 percent in this particular circumstance, where other rate classes have underrecoveries for customer charges where the fixed costs associated with those customers may be substantially higher, simply because of things like meters. 616 MR. BETTS: Thank you. I understand the point you were making now. Thank you very much for that. Please continue. 617 MR. JANIGAN: Finally, on the issue 15.4, there is an issue of the impact of the proposed change in year-end on the proposed cost allocation changes for upstream transportation, storage, peak in service, and interruptible credits. And if we look to the background of this issue, it would set out at tab 11, page 42 of our book of references. And this to some extent is a late-arising issue. And, Mr. Chair, we are somewhat disappointed that this issue has arisen or been opened up by the company and may be supported by other intervenors, that principally, having resolved this matter in the ADR agreement which resulted in the settlement on the basis of a four-year phase-in of costs starting in fiscal 2005 -- and that's set out in the settlement agreement on page 49 of the settlement agreement, which is set out on page 42 of our materials. The phase-in is shown in Appendix B, table 2, which is found on the following page. 618 Now, while the agreement contemplates a potential change based on material change in circumstances, we would submit that this new evidence about a delay in implementation is not sufficient to meet such a test. We believe all parties knew that a change in fiscal year was a possibility, and that the settlement was crafted for a phase-in to start in the fiscal year that commences October 1, 2004, and ends with a final step in October 2007. 619 Now, in examination in-chief by Mr. Cass, which appears on page 43 of our book of references, the implications of the year-end changes to the different aspects of this case were identified. And according to Ms. Giridhar, one of the implications of the change in year-end is the need to alter the settlement proposal with respect to issue 15.4. 620 In effect, if the year-end is changed, Enbridge is of the view that the phase-in of the rate design change as agreed to by all intervenors and subsequently approved by the Board, would shift from an October-to-September year to a January-to-December year, after year 2. 621 And VECC submits to the Board that Enbridge's proposal to shift the phase-in from October-to-September year to January-December year is a violation of the ADR settlement agreement. 622 VECC notes that the settlement agreement regarding issue 15.4, which is set out on page 42, I believe, refers to the beginning of the test year, the time at which changes are to commence. The beginning of the test year is October 1st, 2004. As a result of the phase-in adjustments, they are to begin annually, starting at that date. 623 The ADR settlement agreement, in section 15.4, goes on to state that the phase-in will be carried out over four years. There is no mention that a year period, which, according to any dictionary definition would define a year period to be equal to 12 months, should subsequently be construed to mean 15 months for one of these years, which is what will occur if the Board accepts the Enbridge proposal. 624 VECC submits that the terms of the agreement do not allow Enbridge to shift the recovery period and extend agreement from four years to four years and three months. This, in our view, is a breach of the agreement, if not in the letter, to the spirit of the agreement, that has been negotiated by all parties in good faith and subsequently approve by the Board on this basis. 625 The change would result in real dollars being borne by general service customers that were not agreed to by the intervenors in the ADR process. Now, in cross-examination by Mr. Shepherd, the Enbridge witness, Ms. Giridhar, agrees that there will be an additional subsidy cost being borne by general services customers due to a prolonged period of time which was not agreed to when this issue was settled. 626 If we look at page 44, transcript paragraph 658, it indicates that, in line 68, a question by Mr. Shepherd: 627 "For three months they're out of pocket by about 2 million; right?" Ms. Giridhar indicates "That's right." 628 VECC submits to the Board that the ADR agreement on issue 15.4 should not be altered, as proposed by Enbridge. The October-to-September adjustment for the rate design is a formulaic process that can be carried out either on January or January -- October or January. As a result, VECC submits that there is a requirement by the Board to implement the ADR settlement agreement and to order Enbridge to carry out the phase-in agreement as agreed to by intervenors. 629 In addition, given its formula approach, this can be carried out during the QRAM process, which is similarly a formulaic process. VECC submits that Enbridge's proposal to alter the agreement on issue 15.4 due to administrative difficulties should be rejected. As we've indicated, the company has -- the company is well aware of its desire to change the year-end, and has been aware of this throughout the proceeding, and of such administrative impacts that result from a change. In the event that the company was of the view that administrative difficulties underpinning the October implementation date agreed upon by the ADR negotiations were too complex, such information should have been brought to the attention of the intervenors. 630 VECC submits that the company should never have consented to the ADR agreement in the circumstances that it believed that the year-end change would make the implementation of this complex. 631 It's important to recognize that, as a signatory to this agreement, the company is obliged to live by it. 632 This is an issue of some importance to VECC. As you know, we've filed evidence with respect to this issue, and one of the reasons for the contentiousness of this issue is the underlying question of cross-subsidization between rate classes and the need to ensure that the rate impacts are mitigated, associated with such cross-subsidy. 633 VECC submits to the Board that the ability to resolve this issue among intervenors was an accomplishment that it has put in jeopardy by the alteration at this point in time. 634 However, in the event that the Board approves the year-end change and is of the view that the company's proposal to shift the phase-in from October to January is appropriate to resolve administrative difficulties, VECC submits to the Board that the general service customers, and rate 1 in particular, should not pay for the further cross-subsidy associated with the three-month delay. 635 VECC submits that the Board should order Enbridge shareholders to assume the costs of the three-month further cross-subsidy, as this is a cost associated with EI's desire to align its fiscal year-end among its companies in its corporation. 636 The Board should order EGD to calculate the actual amount of the additional three-month cross-subsidy delay that occurs during the year-end transition and assign the additional costs to the shareholder and refund the general service rate classes for the excess of costs embedded in the rates during those three months. 637 And I briefly just wish to refer to a case which also arises in Connecticut with respect to the change in the fiscal year. 638 MR. SCHUCH: Mr. Chair, we should assign Exhibit K.15.4, and that would be entitled "Application of Connecticut Natural Gas Corporation for Approval of a Change in Fiscal Year," dated January 31st, 2001. 639 EXHIBIT NO. K.15.4: DOCUMENT ENTITLED "APPLICATION OF CONNECTICUT NATURAL GAS CORPORATION FOR APPROVAL OF A CHANGE IN FISCAL YEAR," DATED JANUARY 31, 2001 640 MR. BETTS: Thank you. 641 MR. JANIGAN: And as we've indicated previously in this proceeding, the amount of jurisprudence on changes in fiscal year is rather scant, all of which seems to emanate from the state of Connecticut, for some reason. But in this particular case, it's noted that on the last page of the case that: 642 "The shareholders would pay all of the costs associated with the proposed change to calendar year-end." 643 We would suggest that that's an appropriate principle to be applied in the circumstances of the change to year-end contemplated by Enbridge in this case. And in this case, if the change to the year-end means there is impact to the ADR agreement and the phase-in of the elimination of the cross-subsidy, then that such costs should be borne by EGD and not by the rate 1 customers. 644 Those are my submissions on 15.4. 645 MS. NOWINA: Just for my clarification, Mr. Janigan, on page 44 of your Exhibit K.15.3, where there's the exchange between Mr. Shepherd and Ms. Giridhar and they're talking about the $8 million or the $2 million on a quarterly basis. 646 MR. JANIGAN: That's correct. 647 MS. NOWINA: So to help me understand that, so it's the $2 million we're talking about which you view is a subsidy of rate class 1 subsidizing other rate classes? 648 MR. JANIGAN: If we look at table 2... 649 MS. NOWINA: Where is that? 650 MR. JANIGAN: On page 43. 651 MS. NOWINA: Okay. 652 MR. JANIGAN: And at the end of year 2, there's still an amount outstanding of 3.4 million, if you look on -- 653 MS. NOWINA: Where are you looking, Mr. Janigan? 654 MR. JANIGAN: Under rate 1. 655 MS. NOWINA: Yes. 656 MR. JANIGAN: And you look, after year 3. 657 MS. NOWINA: Right, 3 point -- 658 MR. JANIGAN: 3.4 million. 659 MS. NOWINA: -- 4 million? 660 MR. JANIGAN: That would, of course, change in the circumstances of the delay. 661 MS. NOWINA: So there would be more outstanding at the -- 662 MR. JANIGAN: That's correct. 663 MS. NOWINA: So the question: In the exchange between Mr. Shepherd and Ms. Giridhar, the question was whether or not it was a loss of the $2 million or 3, whatever the amount was, or simply a delay in the receiving it. And that's my question, essentially. 664 MR. JANIGAN: It's a delay in receipt that has a financial consequence. And that's carried for three months in rates. 665 MS. NOWINA: Thank you. 666 MR. BETTS: Those are all the Panel's questions on that issue. 667 MR. JANIGAN: Thank you, Mr. Chairman. I know my friend Mr. Dingwall did not address the question of costs. I will do so briefly, in terms of claiming costs on behalf of VECC on the basis that our participation was responsible. We attempted to co-operate with the other intervenors, particularly in the bringing of evidence in this case. We were part of the Coalitions which brought forward evidence which we believe was helpful in the settlement of certain key issues in the ADR, and we would submit that we managed our participation and intervention efficiently and responsibly to minimize duplication and overlap, and accordingly would request an award of costs of 100 percent of legitimate costs for participation in this proceeding. 668 MR. BETTS: Thank you, Mr. Janigan. And thank you for your submissions and participation in this process. 669 MR. JANIGAN: Thank you, Mr. Chairman. 670 MR. BETTS: And I think before we move to Ms. Aitken, we'll just take a short personal break. Let's nobody leave the floor. We'll aim for just a five-minute break and try to be back here by 3:30 to proceed with your submissions. Thank you. 671 --- Recess taken at 3:25 p.m. 672 --- On commencing at 3:32 p.m. 673 MR. BETTS: Thank you, everybody. Please be seated. The crowd does keep getting smaller, anyway. That's a good sign. 674 MS. AITKEN: Don't take it personally at all. 675 MR. BETTS: Ms. Aitken, are you prepared to proceed? 676 MS. AITKEN: Yes, I am, thank you, Mr. Chair. 677 SUBMISSIONS BY MS. AITKEN: 678 MS. AITKEN: I'm here this afternoon to make representations on behalf of Direct Energy, and as you may recall, Direct Energy only objects to three of the outstanding proposals of EGD. In each case, the proposal in question has the potential, the very real potential, to undermine the fostering of a competitive market. Moreover, in each case, the proposal bears on an issue that's pending before the intended Natural Gas Forum. 679 And so, accordingly, not only is Direct Energy concerned about the impact of the proposals as currently conceived, Direct Energy is also concerned that this Board not prejudge issues that are slated to be explored and probed at the Natural Gas Forum. 680 Just turning to the first issue, then, it's the transactional services issue, issue 4.1/4.2. The effect of Enbridge's proposal to bundle TS assets with the commodity -- oh, pardon me, I just see Mr. -- and quite helpfully so. Thank you. I actually prepared a short compendium to which I'll refer on a couple of occasions, and perhaps I should ask that that be marked as an exhibit. I say "short" in that the excerpts I will take you to are very brief. It's just there for ease of reference. 681 MR. SCHUCH: Mr. Chair. 682 MR. BETTS: Yes, could we have an exhibit here? 683 MR. SCHUCH: We'll mark that as Exhibit K.15.5. And that would be "Compendium of Direct Energy Marketing Limited." 684 EXHIBIT NO. K.15.5: COMPENDIUM OF DIRECT ENERGY MARKETING LIMITED 685 MR. BETTS: Thank you, please proceed. 686 MS. AITKEN: Thank you, Mr. Chair. 687 Just, again, turning to the transactional services issue, the effect of Enbridge's proposal to bundle TS assets together with the commodity is to allow the Enbridge shareholder to exploit its monopoly for TS assets in an anti-competitive way. In doing so, what it does is give Enbridge an advantage, an unfair advantage, that is contrary to a competitive marketplace. 688 What's really in issue is, in November of 2002 -- and I'll be very brief in this regard -- but in November 2002, Enbridge unilaterally started to bundle together with the sale of TS assets commodity that it bought in its own name, in order to enhance the value of the overall good being sold. That activity itself is problematic for the reasons that we will explore. But further, Enbridge is here before the Board asking for two additional changes to this activity that it's undertaken on its own initiative, and those two additional features are that, first of all, Enbridge wants EGS to be able to purchase the commodity that it bundles with TS assets as principal or, in turn, have EGS act as agent for Enbridge in those purchases. 689 The second thing that Enbridge wants is that EGS avoid credit costs associated with the purchase of that commodity insofar as it's purchased to bundle with TS assets. 690 Now, to understand how it works today, quite simply, EGS's principal function is under the agency agreement that it's entered into with EGD to act as Enbridge's agent in conducting a number of things. Those include, of course, the acquisition of gas for system supply, contract negotiation, regulatory support, contract management, and the like. 691 Now, among those activities that EGS performs as agent for Enbridge is the sale of these excess TS assets. And of course these TS assets are assets that the ratepayer has fully paid for, but, at this point in time, are deemed by EGS not to be necessary -- rather by EGD, and then EGS has the power to sell them. There's no question that at the same time EGS remains completely free, on its own behalf and on its own account, to buy and sell in commodity. 692 Now, further to the decision made at the end of 2002, EGS has been doing something else. And what it's been doing is acting as principal in purchasing commodity to package up with these Enbridge assets, these TS assets, to sell in the marketplace, and so what you have is you have Enbridge acting as agent to Enbridge to sell these TS assets; at the same time, you have EGS acting as principal, selling commodity bundled up with these TS assets. And they're offering that bundled product at a single price, a bundled price. 693 And I'll just give you a reference in the transcript. Mr. Jarvis acknowledged in cross-examination that the price charged for this bundled commodity is a bundled price with the TS service embedded into the commodity deal. And that transcript reference is volume 4, lines 152-164. 694 Now, Enbridge tends to characterize this initiative that they undertook as, really, just tacking on some commodity in order to release and to realize the true value of the TS asset. Well, in our submission, it's equally appropriate, and perhaps more so appropriate, to view this as EGS taking commodity and selling more commodity than it ever otherwise would sell, by tacking on some TS assets. And remember, of course, nobody else in the marketplace has the authority or the ability to sell these TS assets. So what you've got EGS doing is selling commodity it would never otherwise be able to purchase and sell, and to augment that value by dipping into its ability to marry that commodity with TS assets. 695 And if I could just ask you to turn to that short compendium of mine, to tab 1C. 696 MR. BETTS: "C" as in? 697 MS. AITKEN: "Charlie." 698 MR. BETTS: Thank you. 699 MS. AITKEN: To line 370, or so. 368, specifically. And I'm just going read a little passage into the record, if I may: 700 "MS. AITKEN: And so EGD, through EGS under your proposal, is increasing the value of the overall transaction by selling the commodity together with the TS asset into the competitive market. Is that right? 701 "MR. BRENNAN: Yes, that's correct." 702 And Mr. Brennan then goes on to talk about the revenues that are generated. 703 And then Ms. Aitken, a few lines down at line 370: 704 "Is it your view, then, that bundling the TS asset together with the commodity enhances the value of the TS asset? 705 "MR. BRENNAN: I don't know that it necessarily enhances the value of the TS asset. I think it increases the value of the product, I guess, for the total bundled service. 706 "MS. AITKEN: So would your answer be the same with respect to the bundling enhancing the value of the commodity? 707 "MR. BRENNAN: No, I don't think it does. I think you need the two together to capture the full value." 708 So, in our submission, it's clear that more value is being achieved for the overall product; in other words, the sum is greater than the parts of the whole -- the sum of the parts is greater than the whole. 709 So, with that introduction, Direct Energy has five principal submissions it would like to make. 710 The bottom line is that this current bundling activity, whether or not the Board accepts the new proposals grafted on or sought to be grafted on by Enbridge, is contrary to what Enbridge, as the monopoly supplier, should be entitled to do. 711 At a time when the whole future of what exactly the role of the monopoly distributor is going to be is a matter of considerable debate. It's inappropriate, in our submission, to enhance the competitive advantage that Enbridge already enjoys out in the marketplace by letting them take this asset, these TS assets, over which they have exclusive ability to sell, and allowing them to bundle that with commodity. Because commodity, of course, is supposed to be the subject of a competitive market, and by allowing a monopoly product to be bundled with it, fundamentally undermines such a competitive dynamic. 712 So the first of our submissions is that EGS isn't authorized under the agency agreement to sell commodity or to sell bundled commodity with TS assets. The agency agreement lists the various things that EGS is entitled, as agent, to sell on behalf of Enbridge, and of course, as acknowledged by Enbridge - they could do nothing else - that list does not include the commodity. 713 While Enbridge argues that the whole spirit of the agency agreement is to realize the most value possible from these assets, the fact remains commodity isn't in that list of things that EGS is entitled to sell. And there's a reason for that, and that is that Enbridge isn't supposed to be in the business of hawking commodity. 714 So notwithstanding the agency agreement doesn't allow for Enbridge to be selling the commodity, EGS went ahead and, with EGD's authorization, made this bundled product and sold it in the marketplace. And for reasons which we'll expand upon, in our submission, this allows Enbridge to improperly leverage utility assets for its advantage to the detriment of the retail player. 715 Our second argument is that it's relatively easy to answer the concern that is cited as the reason for bundling TS assets with commodity. There's no legitimate rationale. And the very activity set the dangerous precedent for hurting the very seed that we're trying to sow of a competitive market. 716 While Enbridge makes some general, vague assertions that there's been a reduction in the number of creditworthy counterparties, or that the volatility in the marketplace requires them to be able to couple the TS assets with the commodity, there's really no evidence to that effect. Rather, EGS has found a way to get more money for the TS assets, and that's by bundling it with commodity. 717 Third, bundling the commodity with TS assets puts EGS in an unfairly advantaged position vis-a-vis the players in the retail marketplace. EGS is the gatekeeper as to whether TS assets will even be offered for sale at all. That puts them in a unique, fundamentally different position than any player in the retail market. 718 EGS acknowledges it has the sole authority to enter into contracts, to negotiate for the price at which it sells TS assets. And as they openly acknowledged, if EGS makes the determination that now is not the most profitable time to sell a TS asset, that it's better to wait until a future time, that's precisely what they do. And there's nobody who can sit in judgment of that decision and there's no opportunity to appeal it. In fact, it wouldn't even be known that it had happened. 719 So if I could trouble you just to see in that same tab, 1C of the compendium, if I could ask you just to turn to line 385, I'm just going to read a short excerpt. Question: 720 "And so if you saw an opportunity in the short-term future to sell a TS asset for more than you could sell it today, you might make the determination, EGS might make the determination not to sell that TS asset until that future time; is that fair? 721 "MR. JARVIS: I believe the answer to that would be yes." 722 And he goes on and says: 723 "And the issue surrounds the fact that at times there is asset available for potential offer of services, but the value that the marketplace would ascribe to that would make it not worth the while of the transaction being entered into, because the value is so de minimus." 724 Now, given EGS's unique authority to decide to sell or not to sell TS assets, by allowing EGS to bundle those TS assets with commodity distorts the competitive marketplace, and it does so for, among other reasons, the following: 725 First, as I've mentioned, EGS is the only one with the authority to sell these TS assets, and, in addition, they have a preferential access to these assets. It has the right of first refusal on behalf of EGD and they access these assets free of charge because they've been fully paid for by the ratepayer. That's a competitive advantage. 726 Now, moreover, what EGS does is it exploits that competitive advantage by burying the price of the commodity into one overall packaged price. Again, nobody has the authority to know what each of the components in the price might be. And as Enbridge, to their credit, has fairly acknowledged, there is no division; they don't even make it internally, or so they say. 727 Now, one has to question the position of Enbridge that that price they offer for that bundle is a market-driven price. There is no market for this bundled product. Only one person offers it and that's EGS. And the only constraint, of course, on a monopolist, is a demand curve. There's no other constraint on price. They don't have anybody else to compete with in selling that unique product. 728 In other words, what EGS is entitled to do by allowing this bundling is to cross-subsidize the amount that it charges for the commodity component. And it does that by bundling the commodity with its monopoly to sell the TS assets. And, of course, cross-subsidization of a monopoly product with a non-monopoly product is anathema to competition. 729 The fourth concern that Direct Energy has with this bundling proposal, or, in fact, the bundling activity that's already ongoing, is the suggestion that, going forward, EGS avoid some of the credit costs associated with their trading in the commodity. 730 Now, EGS's competitors in selling commodity don't have this luxury. They don't get to reach into the ratepayer's pocket to subsidize their costs of carrying on business. But that's exactly what EGS wants the Board to allow it to do. 731 Now, under any of its proposals, because they have three alternative positions, as I understand it, what EGS seeks to do is to shred the credit costs associated simply with doing business in trading the commodity. And that can't be right. Well, it's certainly not competitive. 732 Fifth, bundling the commodity with TS assets encourages distortion in the commodity market in the following way. It builds in an incentive to EGS to only sell TS assets when there's an opportunity to sell them bundled, because from the evidence I read you in the first excerpt, it's clear that the conclusion that EGS has reached is they get more value for the overall product. I think you need the two together to capture the full value. So says Mr. Brennan. Well, if that's the case, EGS isn't going to sell TS assets without the commodity, if it can avoid it. 733 So EGS, acting as a rational monopolist, is going to hold on to those TS assets until they see that the time is ripe, that they can couple them with the commodity and get the highest price. 734 Now, is there's nothing nefarious about that; that's perfectly rational behaviour. Except there is something, in our submission, that would be wrong with the Board blessing it. A corollary of that what we would call anti-competitive incentive, is that it may even encourage EGS to hold assets, TS assets, off the market while they're waiting for this good opportunity. And to the extent that there are liquidity concerns about which we've heard quite a bit from Enbridge, those concerns would only be aggravated by allowing them to govern their own behaviour according to this incentive. 735 A further corollary of that market power would be that, by being the only ones out there able to offer this more appealing product to the consumer, this bundled product, it may deprive the retail marketers of the opportunity even to bid for the commodity component of that business. They might not even know it was happening, and accordingly, they might be shut out of that activity. 736 Now, it's worth noting parenthetically, I've reviewed Mr. Shepherd's submissions on behalf of the Schools, and he makes much of the fact that there's no evidence in the record that retail marketers would be prejudiced by this bundling activity. Now, with respect, this isn't a matter of evidence. This is a matter of simple logic. 737 Take this example. You have a company that can sell widgets, and it competes with other companies in selling widgets. In this case, the widgets are the commodity. Now, that first company also, and alone, has the ability to sell gidgets. So they sell widgets plus gidgets and they compete with those who only have the ability to sell widgets. Now, given that gidgets have an enhanced value in the marketplace, particularly when coupled with widgets, who do you think is going to sell more widgets? It's going to be the company who's got that monopoly product; that they have the discretion to add or not to their widget to enhance the value. 738 And this is particularly aggravated in the situation where the price is not transparent. The consumer has no way of knowing what they're paying for the commodity element of this bundled product. And so the competitive implications of this bundling activity include a reduction in choice, and in transparency. And both those elements, of course, are fundamental hallmarks of a competitive market. 739 Now, I'm just going to read, I'm not going to bother you to turn up, but I'll just read you, and I'll give you the reference. I'm reading in that same tab, at line 351, question: 740 "So when you're actually out there offering this bundled product for sale, it is not broken down, the difference between what you are charging for the commodity and what you're charging for the TS asset? Or is it simply just offered as a bundled price? 741 "MR. JARVIS: It's generally offered as a bundled price. I can't think of a circumstance where there's a so-called commodity fee or commodity charge that would flow to the bottom line of what the margin -- resulting margin is." 742 Question: "So it wouldn't be transparent, then, to the purchaser? 743 "MR. JARVIS: Correct." 744 And so the question of choice is compromised in that TS assets are being just sold as a bundled good for the most part, and as well, transparency is compromised in that consumers just have no way of test whether what they're paying for the commodity element is fair or not, whether it's competitive or not. 745 And as a matter of law and, frankly, of practice, it is -- and I focussed a lot on competition and competition concerns -- but it is the mandate of this Board to monitor whether this is competitive activity or not, because the reality is, of course, that due to the regulated conduct doctrine and the spirit of documents such as the joint statement between the Competition Bureau and the Energy Board, the reality is that the bureau is, for the most part, going to defer to this Board to watch that sort of behaviour. 746 So, in conclusion on TS assets, and for all those reasons, Direct Energy's submission is that the Board should recognize that the bundling of commodity transactions on Enbridge's behalf with traditional TS assets is contrary to existing authorizations under the agency agreement and this Board's authorizations. As such, in our submission, the Board should not permit bundling. 747 Now, in the alternative, if this Board is inclined to do so, in our submission, the Board should not permit EGD to engage in the trading of commodity in its own name. The anti-competitive messages in allowing the monopoly distributor to effectively trade in the commodity in a non-neutral way is, in our submission, something that this Board ought not to condone. 748 Likewise, in our submission, the Board should deny EGS's request to shift to ratepayers the credit costs associated with their commercial trading in the commodity. 749 Those are our submissions on transactional services, if you have any questions? 750 MR. BETTS: Just one, Ms. Aitken. If the Board were to prevent EGD from bundling either with EGS or on its own the commodity with the TS asset, is there another market they could go to in order to maximize the TS asset for the ratepayer? 751 MS. AITKEN: Another market they could go to? I'm sorry? 752 MR. BETTS: What would they do with that asset? How would they manage it? Can they offer it in the open marketplace and get a fair value for it? 753 MS. AITKEN: They can certainly, and would be free according to the very clear terms of the agency agreement, to sell those assets for whatever the maximum price they can get is, and I would suggest that given the incentive that they would necessarily have, if deprived of the opportunity to bundle with the commodity, you might see that the volume of TS assets sold solo might well be more than $8 million. 754 MR. BETTS: Thank you. Please proceed. 755 MS. AITKEN: Thank you, Mr. Chair. 756 Just turning, then, to the second issue, the storage contract. This is issue 5.1. 757 Enbridge seeks approval of the cost consequences of a new storage contract entered into between Enbridge and Union effective April 1, 2004. Now, that new contract purported to terminate the old contract, but that old contract wasn't due to expire until March 31, 2006. 758 Now, that old contract, of course, was at cost-based prices. Now, had Enbridge stayed with that old contract until March 31, 2006, or if this Board denies this request for approval of the new contract, in either of those two events the ratepayer will continue to enjoy cost-based rates until March 31, 2006. 759 Now, Enbridge wants the Board to approve the cost consequences of the new contract. And what that new contract does is, it introduces negotiated rates immediately. In the first two years, the cost of that is a substantial premium to the ratepayers, because instead of paying the lower cost-based rates, they're now paying negotiated rates right away. 760 Now, Enbridge argues that that premium that the ratepayers are stuck with, if the cost consequences are approved, is worth it, because they say: We were able to negotiate better long-term rates, as compared to what we predict would have been the market-based rates starting in year 3, going through to year 10. 761 Now, Direct Energy objects to the request for approval on three -- or four, rather, four principal grounds. 762 First of all, the premise that is set up as the reason that Enbridge sat down and negotiated early a new deal with Union is seriously questionable. What Enbridge says is that they had a dispute with Union about the termination date of the contract and that therefore they feared litigation and they thought that they had to sit down with Union and negotiate a new deal. 763 Well, the fact of the matter is, Enbridge's own evidence is that they were quite confident that they had a strong case - those were their words, "a strong case" - on the termination date. Moreover, there isn't the slightest hint from Union that litigation was a possibility. 764 I think significantly, in its evidence in cross-examination, Enbridge conceded that nobody ever did a calculation of what the risk of that litigation might be, and in our submission, that's a pretty telling indicator of just how concerned they really were about this threat of litigation. 765 Perhaps not surprisingly in those circumstances, they didn't do that because of the inchoate nature of this risk. Nobody sent them a demand letter. Not so much as a demand letter. 766 Second, the estimate of the future market-based prices on which Enbridge relies to say, Look, the negotiated ones we got are way better, is highly problematic. There's a number of problems with their predictions. 767 The first of those is that they took two bids that were submitted in response to an RFP that were never the subject of any negotiation. Now, that, of course, is in stark contrast to the Union bid, because you'll remember, Enbridge's evidence was, Well, the understanding was, Union, you come up with your "best deal" or "best offer" and then we negotiated it for six months. 768 The two bids that formed the foundation for the benchmark that Enbridge urges on this Board were never the subject of any negotiation. Accordingly, this benchmark on which they rely was subject to no testing, independent or otherwise. In fact, Enbridge concedes that the exclusive reference point that they consulted for future market-based prices were these two bids submitted in response to an RFP that they didn't probe and had no communication with the bidders about. 769 Now, in presenting this predicted market-based price as the benchmark, all they did was average those two bids, again, those two non-negotiated bids, and so beyond the frailties inherent in looking at a non-negotiated bid as against a negotiated contract with Union is the failure to necessarily reveal what the best of those two bids was. So by averaging them, one of the deals or one of the bids, rather, could have been preferential, or preferable, rather, to the Union bid, but we'll never know that because they got muted; they got averaged. 770 Moreover, the Board has no way of testing whether what I'm saying or what Enbridge is saying is more reasonable. You, like myself, have no way of knowing what those bids contained, because, of course, Enbridge has taken the view that the bidders communicated to them that that was commercially sensitive information, and so nobody has an opportunity to probe them. 771 Now, there's nothing wrong with that position; it's a perfectly fair one to take. But at the end of the day, it's Enbridge's burden to demonstrate that the numbers they've put forward as the predicted market-based price are reasonable. In our submission, an untested average of two non-negotiated bids is simply not enough to satisfy that burden. 772 Moreover, given the uncertainties in the marketplace, it's not reasonable of Enbridge simply to have sent out an RFP for a ten-year deal. Enbridge themselves acknowledge that they don't know with any certainty what their needs for storage will be, going forward, and they certainly don't know what the market may look like after the debate in the Natural Gas Forum. 773 The third basis on which Direct Energy objects to the approval of the cost consequences of this contract is that it is not favourable to ratepayers. The ratepayers will suffer for two years by having to pay rates considerably in excess of the cost-based rates to which they are entitled. And EGD has not substantiated its market-based predictions. 774 Moreover, a ten-year contract is too long in a changing marketplace. Enbridge acknowledges that they can't terminate that contract early. 775 There are two features to the contract that Enbridge makes much of in showing all the flexibility that they've built into this negotiation -- negotiated contract. 776 The first is they say, Oh, well, we can assign it; there's an assignment right under the contract. Well, as they conceded on cross-examination, and is absolutely clear on the face of the contract, Union has reserved that right to itself, to agree or not agree to an assignment request by Enbridge. And as Enbridge further conceded on the stand, there's absolutely nothing to stop Union from exercising its discretion in that regard entirely unreasonably. 777 And so what you have is you have Union with a significant degree of control over how Enbridge can respond to a changing market environment. 778 The second option about which Enbridge makes a great deal in terms of saying what a good contract this is for ratepayers in terms of flexibility is the ability to withdraw a certain amount of storage commitment under the contract. 779 Now, in our submission, that flexibility is somewhat illusory. First of all, you can't do it without two years' notice. Secondly, it's only triggered if EGD or one of its affiliates actually develops new storage and wants to use that particular storage to replace the storage that would be being withdrawn from Union. 780 So that means that Enbridge can't just reduce the amount of storage it needs and therefore reduce its requirements to demand that storage from Union. It also means that Enbridge can't reduce its storage if a better offer comes along from a third party, no matter how good that offer is. 781 And so at the end of the day, Enbridge is stuck. They are locked in, subject to this very narrow reduction of 20 percent, with two years' notice, and under only very specified clear terms of it being an Enbridge substitute of storage. 782 The fourth and final concern that we have is this contract is an attempt to prejudge an issue that is slated to be considered in the Natural Gas Forum; namely, should the Board continue to regulate storage, and if so, how? 783 In particular, Direct Energy is concerned that entering into a ten-year contract while this review is pending is premature and could constrain the unbundling of the storage function that would otherwise facilitate daily balancing and upstream asset optimization by retailers and large-volume customers. 784 A long-term contract of this nature, ten years in duration, may impede the development of a competitive storage market. Indeed, a cynic might argue that Union had that in mind in building in the protections that it did. 785 Now, in sum, Enbridge's rationale for going ahead with this contract is based on unsubstantiated assumptions that the Board will necessarily be headed toward market-based priests for storage, highly questionable estimates of future market-based prices against which Union's negotiated prices are evaluated, and vague assertions that price and demand will both continue to rise. 786 For these reasons, Direct Energy urges the Board not to approve the cost consequences of the new contract. Rather, the Board should allow ratepayers to continue to enjoy the two years of cost-based rates to which they are entitled under the old contract. This would also allow the Natural Gas Forum to run its course, and decisions could be made in the context of greater clarity following that debate. 787 If there's no further questions on -- or any questions on that at all? 788 MR. BETTS: The Panel has no questions on that issue. 789 MS. AITKEN: So then just turning to my third and final issue, and that's risk management, issue 5.2. 790 Direct Energy objects to only three of the substantive proposals that Enbridge makes in connection with risk management: The first is the proposal to change the objective to the risk-management program, the second is the proposal to increase hedgable volumes in discrete transactions by removing that 10 percent cap, and the third is Enbridge's proposal to hedge volumes on a 12-month rolling basis. 791 Simply, Enbridge's position is that no changes should be made to Enbridge's risk-management program at this time. We have three principal submissions. Sorry, I believe I said Enbridge's position. I meant Direct Energy's position. 792 First of all, there's no urgency to making the changes that Enbridge is proposing. And to make any changes now would risk preempting decisions made in the context of the Natural Gas Forum. 793 The issue of risk management is slated for consideration by the Board on a broad policy basis. Specifically, the Board is to consider the role of the distributor in providing system gas supply and "how might the gas distributor in a regulatory context better respond to changes in natural gas prices?" 794 Indeed, on June 24th of this year, the Board released a notice that said that the policy forum will include "the role of distributors in providing system-gas, including pricing." Well, pricing, of course, is a function of how well you've risk-managed. 795 Even EGD, while resisting the immediacy of when the forum is going to take place, and none of us know that, to be fair, did concede that there was overlap between the proposals they had before the Board and those issues that would be dealt with in the Natural Gas Forum. Accordingly, any changes now that would signal a policy shift would be premature, given the Board's indication of what they want to look at in the context of risk management. And in that sense, approving any of these three issues that we've identified, the objective, 10 percent cap removal, and the 12-month rolling basis, any of those would, in that sense, frustrate the Board's intentions. 796 Furthermore, there's no justification for making this change now to the status quo. Enbridge's own risk-management consultant, Mr. Simard, acknowledged in his report and on cross-examination two things, two very important things. 797 First of all, he acknowledged that the objectives of the current risk-management program are, "generally sound." The second thing he acknowledged was that, "best industry practices are in place and are being observed." Best industry practices. 798 So, accordingly, in our submission, the highest that these proposals could be put is the potential for prudent recommendations for future conduct. And those are Mr. Simard's words. It is decidedly not as any kind of a need to address a system in distress. Quite the contrary. Best practices are in place, and are being observed. 799 Secondly, specifically with respect to the proposal to change the objective of risk management, this involves moving to further decrease price volatility. Now, this mutes pricing signals sent to consumers in reaction to fluctuations in commodity prices. There's no getting around that; it mutes the signals. 800 System gas prices should be reflective of market prices on an ongoing basis. This is a fundamental principle underpinning system supply pricing, and indeed, is reflected in Enbridge's own current QRAM guidelines. 801 Now, increasing risk-management activity with the objective of decreasing further volatility in prices interferes with - and I come back to this - the fostering of a competitive environment. Indeed, Enbridge, in cross-examination, expressly acknowledged that decreased price volatility, the objective they now cite, reduces the attractiveness of a gas marketer's fixed-rate alternative. So what we have is we have Enbridge introducing into the pricing of system-gas a feature to try to make it more attractive. Now, they don't put it in those words, but that's what it is. It diminishes the differentiation between the menu of options that the gas marketers have and the option, which is only supposed to be a default option, of system supply. 802 Choice is further eroded as well, in that no longer will that customer, who likes the ride, who likes the risk, the ups and the downs, no longer will they be able to have that through system supply. 803 Third, the cost associated with this changed objective is not neutral. You want to reduce risk, you want insurance: It costs you something. So, instead of just following the objective of competitive markets, and allowing the menu of options to be offered by the retail marketers who are competing in selling their product, Enbridge instead decides that it wants to impose on the ratepayer a different option, and they want the ratepayer to pay for that. 804 The offerings made by retail marketers are more efficient because they bear the weather risk. Now, Mr. Simard indicated that, over the long run the expectation is that the gains and losses associated with the program will net off to zero. Now, given this statement and the fact that the operation of this program results in incremental O&M expenses and transaction costs, the program that Enbridge wants to implement amounts to an expensive deferral of costs over time. 805 Now, if what we're looking to do - and it's a perfectly valid objective - is to introduce a measure of stability and predictability into system gas prices, well, that's already being done. You've got the equal billing plan. And, in our submission, that is the appropriate measure of stability and predictability that belongs in a system gas option. 806 Leave it to the retail market to come up with, to design and to offer, the various menu of options that consumers may be interested in, because fundamentally, that's how this market is supposed to be being designed. System gas supply is not supposed to be being promoted to take or to retain market share, if you will, from retail marketers. 807 Now, another cost associated with decreasing volatility, is that that customer who wants to enjoy the downward pressure on market prices doesn't get to do that anymore. It has a much more muted experience. And that may not be what that customer wants. 808 Another is that in the short to medium term, at least, ratepayers may pay a significant amount for this hedging activity. Indeed, in 2002, the differential due to risk management was in the order of $40 million. Guess who paid for that? That was the ratepayers. Indeed, that was what prompted the RiskAdvisory report being mandated in the first place. 809 Yet another cost that may be introduced into the system is further to Enbridge's proposal to move to a 12-month rolling basis. Now, as they acknowledged to their credit, and they filed no evidence about it, they haven't studied the implications of this move. Now, in those circumstances, Enbridge hasn't discharged its burden of proof that this change is desirable, let alone necessary. And this will be the last time I'll take you to the transcript if I could -- oh, actually, you know what, this is not in our compendium, so I'll just read it to you. 810 This is from volume 2, line 1360. And these are questions from the Board in the context of risk management. And I'll just read this to you. It starts at line 1360: 811 "MR. SOMMERVILLE: There is one question, Mr. Pleckaitis, you indicated in one response that the -- or perhaps it was you, Mr. Brennan -- that the company did not study the interplay between the rolling 12-month proposal and the QRAM, and how that was going to be operational accommodated. That surprised me a little, and I'm wondering what kind of an obstacle have you seen in that kind of accommodation? 812 "MR. BRENNAN: It's a very difficult problem, I guess, if you like. I shouldn't say it's a problem, but it's a difficult situation in how we're going to deal with this, because in terms of how the reference price is set each quarter, and what does that mean going forward as to what that tolerance amount should be." 813 Now, Mr. Brennan goes on, but the point is, it's a "difficult situation," the implications of which have not been studied, let alone resolved. And in those circumstances, in our submission, this lends a further air of prematurity to Enbridge's proposal. 814 Not only is there a real risk that this consideration by the Board may be superseded and very soon, by whatever takes place in the Natural Gas Forum, but Enbridge hasn't even studied the implications of certain parts of its proposal. 815 Finally, removing the 10 percent cap introduces increased risk to ratepayers by reason of decreased diversification. By removing the cap, Enbridge could, through a single transaction, put all its eggs in one basket. And by treating its portfolio this way, there is the potential for ratepayers to be prejudiced and to suffer as a result of the reduction in diversification of risk. 816 To try to address Ms. Nowina's question this morning to Mr. Dingwall, the 10 percent cap removal is not just an incremental change to the existing program. It is associated with a change in approach, a change in policy, to further and consciously smooth out the price experience for consumers. And that's exactly what policy issue the Board is slated to consider in the forum. 817 Now, moreover, as a pure evidentiary question, Enbridge hasn't demonstrated that these changes are desirable. They simply say more hedging is good. Well, what hasn't been demonstrated is that more hedging is, on balance in these circumstances, good for the ratepayer. 818 Moreover, by removing that cap, that 10 percent cap, and allowing additional hedging activity, what that does, further to the change in objective, is to further mute the signals to the consumer about changing market prices for the commodity. And again, for the reasons that I've submitted earlier, that is not something that -- well, it's certainly premature, and it's not something that is consistent, in our submission, with the way that the market has been organized in terms of creating a competitive market for retail marketers and having system supply as merely the default supply and one that doesn't, per se, compete for customers. 819 Now, for all those reasons, Direct Energy urges the Board not to accept any of Enbridge's proposals with respect to risk management in connection with changing the objective, in connection with increasing the hedgable volumes by getting rid of the 10 percent cap, or to change to a 12-month rolling basis. 820 The matter is scheduled to be heard by the Natural Gas Forum at the appropriate high-level policy consideration. And to make a change in the meantime, in our submission, when there's no demonstrated urgency whatsoever - remember, best practices are being observed - when that's the case, in our submission it would be ill-advised for this Board to wade into that territory. 821 This is ever the more so in the specific circumstances of Enbridge's proposals. In our submission, Enbridge hasn't discharged its burden of showing that these proposals are advisable or certainly that they're necessary. 822 In particular, by increasing the utility's role as the muter of gas price volatility, Enbridge's proposal is tantamount to getting into the business of making its offer, system supply, more attractive than the supply offered by retail marketers. Now, in that way, it has the real potential to undermine the competitive market that so much effort has gone into to try to foster. And that's how, Mr. Chair, in response to your question this morning, the change as a mechanism to decrease price volatility risks real harm. 823 Moreover, the proposal would limit the choice of the consumer by everybody basically getting into the same game, everybody getting into muting price volatility and dispensing with those signals to the consumer of the real market price. 824 Now, if the Board at the Natural Gas Forum wants to change the world and they want everybody to play the same game, well, there's nothing illegitimate about that if they want to do that. But if they were to do that, it would be a fundamental shift in policy, and one that, while Enbridge urges the Board to do it today, we would strongly encourage the Board to resist. 825 Naturally, my colleague points out, the corollary of such a fundamental shift, if, in fact, that was mandated by the Natural Gas Forum, is that everybody would start to have to play by all of the same rules. So you wouldn't have the retail gas marketers acting in this prejudiced position, competing with the monopoly distributor of system gas. 826 Does the Board have any questions on those submissions? 827 MR. BETTS: Questions? No, we don't. Thank you. 828 MS. AITKEN: Thank you, Mr. Chair. 829 MR. BETTS: That concludes your submissions? 830 MS. AITKEN: It does. 831 MR. BETTS: Thank you very much. You were very helpful. And we appreciate your participation in this proceeding. 832 MS. AITKEN: Thanks. 833 MR. BETTS: And, Ms. Jackson, I think -- first of all, welcome. 834 MS. JACKSON: Thank you. 835 MR. BETTS: And I think you heard us say that we had until 4:45. So it's over to. 836 MS. JACKSON: I'm pleased, at this late hour in the afternoon, to be able to report that I have one issue to address, and I will be brief. 837 MR. BETTS: Thank you. Please proceed. 838 SUBMISSIONS BY MS. JACKSON: 839 MS. JACKSON: The issue that I'm here to address is the question of the establishment and content of the class action suit deferral account. And, briefly stated, Union Gas supports the request of Enbridge for the continuation of the account and with respect to the amounts that are proposed to be posted in it from time to time. 840 In essence, it is our submission that this is a classic situation in which a deferral account is called for and appropriate. The applicant has indicated that it looks, in the future, to attempt to recover in rates amounts which it may well have to expend during the rate year, which are known to be potentially very significant but which cannot be reliably forecast during that test year. 841 Importantly, though, in my submission, the classic test for establishment of a deferral account does not include the issue at which so much attention seems to have been drawn in the last two years -- two days. It does not require any advance determination as to whether any of the amounts that are to be posted in the account will, in fact, be recovered. 842 This Board has said precisely that at the outset of day 5, when you indicated that that was not an issue before you in this case, and indeed, in my submission, the Act itself makes that clear when it says in section 36(4.2) that the question of the clearance of a deferral account at a regular interval will specifically address: 843 "An order under this section that determines whether and how the amounts recorded in the account shall be reflected in rates." 844 So it could not, in my submission, be clearer that the false strawman that's been put up, to some extent, the question of whether the creation of the account or the allowance of amounts to be posted in it anticipates in any way that those amounts will be recovered is just not so. It's not so in general and it's certainly not so in this case. 845 But what it does do is it allows the Board to make a decision on whether the amounts that will fall into that account over the period in which it is created, whether those amounts can be recovered in rates at a time when the Board has sufficient information, including information with respect to the amounts, including information with respect to all the other issues that have been raised by those who query this account; information with respect to mitigation; information with respect to anything else that anybody says might be relevant to the question of whether or not those amounts should be recovered. 846 That information is not available today. In large measure, it simply cannot be available today, because we should recognize that this lawsuit, although it's gone on for ten years, remains a lawsuit about equitable remedies. And the question of whether Enbridge will be liable and in what amounts remain to be determined by the court. 847 So it would, of course, be premature to attempt to determine whether those amounts, if they are paid, should be recovered in rates. But it is entirely appropriate, in my submission, to take steps to ensure that when that information is available, the issue can be fully and properly addressed, and that it can be addressed without engaging in retroactive rate-making. That is precisely why the Board does sometimes create deferral accounts. And in my submission, it is precisely why, in this case, it's appropriate to create a deferral account. 848 Now, as I read and hear those intervenors who query the propriety of the account, the focus of the concern is, I think, not on the creation or the continuation of the account, per se, or the continuation of the posting in the account of the costs of defending the class action. The controversy for the few intervenors who raise elements of controversy focuses, I think, on two things. 849 One, the suggestion that with respect -- and both of them have to do with the proposal that the amount -- that the account might also contain any amounts of a judgment that is paid during the test year -- or during the 2005 year, including, if and when such orders are made, the question of the plaintiff's costs. 850 I think the concerns, if I may put it that way, that have been raised with respect to those amounts have two principal focuses: One, the suggestion that to create an account into which those amounts might be posted, at this stage is in some fashion premature; or, secondly, that those amounts -- that the creation of the account implies that the Board has made some preliminary determination about the recoverability of the amounts, and it would be inappropriate for the Board to make such a determination. Let me look briefly at each of those concerns. 851 The prematurity concern. Well, it's true that this litigation has been outstanding for ten years, but the pace of the litigation is such that it is within the realm of real possibility right now that this matter may be resolved within the period encompassed by the account. I say that simply as an outside observer looking at the fact that the Supreme Court of Canada has now given very detailed guidance with respect to this case on two occasions. And while there's much yet to be resolved, a lot has been. And it is by no means inconceivable or unreasonable to suppose that this class action could come to fruition within the time frame, that is, before the end of calendar 2005. I have no particular inside information, of course. And I don't think, with respect, that the Board should be pressing Enbridge for that either. Because they are still involved in some very difficult and high-priced litigation. And what we can say, since they're seeking to establish the account and seem concerned about the possibility that a judgment might be payable within the 2005 period, that there must be some sense that this is within the realm of possibility, and beyond that, in my submission, it would be unwise to press Enbridge as to what its thinking about that litigation is. 852 But I also say, and perhaps more fundamentally, this suggestion of prematurity is, in my submission, a red herring. If amounts with respect to judgments and plaintiff costs are ordered within the period contemplated by the account, then it's very important that that account be there for those amounts to be posted in order that the Board can then undertake a thorough analysis of whether they should be recovered in rates. And if they are not forthcoming in that period, there's nothing in the account, and there's nothing to worry about. 853 So, in my submission, the suggestion that the account should be able to take those amounts if they are found to be owing and paid in the year is prudent, and does not in any sense jump the gun. But I think, in fact, the real focus is not so much on prematurity, but the suggestion that by merely creating the account, even if the amounts aren't posted in the 2005 year, the Board is somehow saying something about whether, if such a judgment is forthcoming, all or part of it might be recovered in rates. 854 I think Mr. Thompson yesterday put it quite squarely. He said it implies that some portion of those amounts will be recoverable. In my submission, that's not so. It's not so in general. I say that as somebody who has both successfully attacked and unsuccessfully defended deferral accounts that have not been fully recovered on behalf of the utilities. 855 It's clearly not so in the statute. And I took you to the words earlier, where the statute clearly contemplates that, at the time the Board comes to make a decision and only then, the Board would determine whether the amounts are to be recovered in rates, and if so, how. 856 And finally, in my submission, the Board can't have been any clearer with respect to this particular case that that is not the issue that you consider that you are addressing at this stage. However, it does allow the Board to make a proper decision on the necessary information, when that information as to amounts, mitigation, any associated judicial determination of why, if any, of those amounts is appropriate, is available. 857 Flipping it over, though, in my submission, asking the Board not to create the deferral account or not to allow amounts of judgment or plaintiff's costs to be posted in that account if those payments are made is, in effect, in my submission, asking the Board to make a determination now before the necessary information becomes available, that the amounts cannot or should not, or are likely not recoverable in rates. And, just as it would be premature to decide that they are, in my submission it's premature to decide that they cannot be. 858 And for the same reason, for the same reason advanced by the intervenors that the Board ought not to decide this issue now, in my submission, it ought not to decide the issue by not creating the deferral account. 859 And indeed, in my submission, not to allow those amounts to be posted in the deferral account, in fact, runs contrary to precisely what the Board said it was going to do at the beginning of day 5, which is not address recoverability. Not allowing them to be posted does address recoverability, and in a negative way. 860 It's also, in my submission, contrary to what those interested in this issue have been led to believe by the Board's fact sheet. That's been filed in these proceedings, as I understand it, at Exhibit K.5.4. And that fact sheet specifically contemplates that utilities such as Enbridge might seek to recover in rates amounts that they are ordered to pay by way of restitution of late-payment penalties. And the fact sheet goes on to say: 861 "The Board will make its determination on rate recovery of any restitution payments following a public hearing in which the views of utilities, other parties, including consumers groups will be heard." 862 In my submission, that must mean that there will be proper notice to people that these issues are being considered, and they'll have an opportunity to participate. Here, in my submission, the Board having said that the issue will not be decided in this case, this hearing is clearly not the public hearing contemplated in the Board's fact sheet. 863 The issue is one, of course, of significance. It's of significance not just to Enbridge; it's of significance to Enbridge's ratepayers and stakeholders, and it is, of course, going to be of significance to all the other utilities in Ontario, all of whom, I believe, now have been sued. 864 And in my submission, it is a classic case for a fully informed and thoughtful decision-making process when the necessary information is available and not before. On behalf of Union, I urge you not to do anything to prejudge the outcome of that hearing when it occurs, and I urge that the proper way not to prejudge the outcome is to allow the deferral account in order that the amounts may be posted and the issue considered when and if the information is available. 865 And those are my submissions, if you have any questions, I'd be happy to answer them. 866 MR. BETTS: Thank you. No. We have no questions. Thank you very much for that submission. And thank you very much for being very effective in your use of time. 867 MS. JACKSON: Thank you. 868 MR. BETTS: I think that concludes the day's activities. We will be reconvening tomorrow at 1:00 p.m. to hear arguments from one more intervenor, representing three intervenors, I should say, and that's Ms. DeMarco. 869 So for those of you that are coming tomorrow, I'll say: See you again. And for those of you who are not, I'll say: Thank you very much for your participation, and we'll see you some time in the future. 870 We'll adjourn now until 1:00 p.m. tomorrow afternoon. 871 --- Whereupon the hearing was adjourned at 4:39 p.m.