Rep: OEB Doc: 1388T Rev: 0 ONTARIO ENERGY BOARD Volume: 13 9 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 Friday, 9 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 9 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 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 VALERIE YOUNG OAPPA, Casco, Maple Lodge Farms, Markham District Energy MURRAY ROSS TransCanada PipeLines 8 TABLE OF CONTENTS 9 SUBMISSIONS BY MR. CASS: [31] SUBMISSIONS BY MS. PERSAD: [171] SUBMISSIONS BY MR. O'LEARY: [273] PROCEDURAL MATTERS: [352] SUBMISSIONS BY MR. O'LEARY: [366] FURTHER SUBMISSIONS BY MR. CASS: [521] 10 EXHIBITS 11 EXHIBIT NO. K.13.1: BRIEF SUBMITTED BY THE APPLICANT FOR ARGUMENT IN CHIEF ON DEFERRED TAXES [35] EXHIBIT NO. K.13.2: DOCUMENT ENTITLED: BRIEF SUBMITTED ON BEHALF OF ENBRIDGE GAS DISTRIBUTION INC. FOR ARGUMENT IN CHIEF ON ISSUES 13.1 AND 13.2, CHANGE OF YEAR-END [531] 12 UNDERTAKINGS 13 14 --- Upon commencing at 9:40 a.m. 15 MR. BETTS: Thank you, everybody. Please be seated. 16 Good morning, everybody. Today we begin, and I don't want -- I hope none of you are superstitious, but day 13 of this hearing, the hearing of application RP-2003-0203, and today is dedicated to receiving arguments in chief from the company, the applicant, in this matter. 17 Before we begin with that, are there any procedural matters to be dealt with? 18 MR. CASS: No, sir, there are not. 19 MR. BETTS: Okay. Then I think we should just begin, then, with arguments, and I see three members of counsel for the applicant. Could you tell us how you intend to present your arguments to the Board? 20 MR. CASS: Yes, Mr. Chair. If I might lead off and, in fact, begin by explaining to the Board the company's plan for argument. I propose to make the first set of submissions to the Board and they will address the deferred taxes issue. After that has concluded, Ms. Persad will submit argument on three issues in the following order: The Union Gas storage contract, rate design issues, and the class action suit deferral account. When Ms. Persad has finished those submissions, Mr. O'Leary will address risk management, transactional services, and the DSM issues, the DSM issues being the point about boilers and also the impact of the year-end change, if approved, on DSM. Then at the end, Mr. Chair, I will have a further submission and that will relate to the broader issues about the change in year-end. 21 MR. BETTS: Thank you. Appreciating that there are three of you involved with this, any prediction on time? I find if you -- if we ask you that, that often it helps you focus on how long you're going to be. 22 MR. CASS: Well, Mr. Chair, others said to me this morning that they were thinking that we might be in a position to finish by lunch. I'm not so sure. I have somewhat lengthy submissions on both deferred taxes and the change of year-end, so I suspect that it will take us somewhat longer than lunch, but I hope less than a full sitting day, till 4:00. 23 MR. BETTS: Thank you. That's helpful. And the Board is prepared to spend as much of the day as is necessary to hear arguments in chief. With that, and thank you for the outline, would you like to proceed? 24 MR. CASS: Yes, thank you, Mr. Chair. 25 MR. BETTS: Please do. 26 MR. CASS: One final point, if I may, in relation to the various submissions that you will hear, when I'm making my submissions, I don't mind at all and in fact I would encourage questions from the Board even as I go through my submissions rather than saving them to the end, if the Board wants to ask questions as particular points are being addressed. In any event, though, I would think that as we move from issue to issue, if the Board sees fit, that perhaps the questions on the particular issues could come at the end of each submission rather than having them all at the end of the day. But, again, I would leave that with the Board. I'm content to answer questions on my submissions at any time as I go through them. 27 MR. BETTS: And could I hear from Ms. Persad and Mr. O'Leary, what is your feeling with questions? 28 MS. PERSAD: I agree with what Mr. Cass is saying, Mr. Chair. I'm comfortable with answering questions that the Board may have throughout my submissions, or if the Board prefers to wait until the end of each issue to ask questions, that is fine with me as well. 29 MR. O'LEARY: And my position or view is exactly the same. I would invite questions when they come to mind. 30 MR. BETTS: Great. I think the Board would find that to be beneficial as well, so thank you very much for that offer and please proceed. 31 SUBMISSIONS BY MR. CASS: 32 MR. CASS: Mr. Chair, for the purposes of deferred taxes issue, I have preferred a small brief. This follows from a submission that the Board made indicating that this form of brief might be helpful. The company will not be doing this on every issue, but certainly in relation to deferred taxes, I believe that it will be of assistance. I should point out that every single item in this brief, without exception, comes from the existing record. There is nothing new being added to the record. As I address the items in the brief, I will be able to tell the Board exactly where in the record they come from. 33 MR. BETTS: Let's establish an exhibit number for this. 34 MS. LEA: K.13.1, please, and it is the brief submitted by the applicant for argument in chief on deferred taxes. 35 EXHIBIT NO. K.13.1: BRIEF SUBMITTED BY THE APPLICANT FOR ARGUMENT IN CHIEF ON DEFERRED TAXES 36 MR. BETTS: Thank you. 37 MR. CASS: Mr. Chair, as the Board is aware, the deferred taxes issue in this case concerns the company's proposal to draw from what is called the notional utility account. That notional utility account was established as a result of the Board's decision in the EBO 179-14/15 case. I've included at tab 1 of Exhibit K.13.1 just some -- the relevant extracts from the 179-14/15 decision concerning the notional utility account. Just to indicate where this comes from, the existing record of this case, the material at tab 1 of the deferred taxes brief is part of Exhibit K.7.3, specifically at tab 2A of Exhibit K.7.3. 38 The notional utility account was established essentially in paragraph 3.3.19 of the decision that is at tab 1 of the brief. Perhaps I should just read for the record what is stated there rather than attempting to paraphrase the words. At paragraph 3.3.19, it is stated: 39 "It therefore appears to the Board that utility ratepayers have benefited from the rental program over the years, and that the shareholder has absorbed some costs. While finding that the ratepayers should not be responsible for the deferred tax liability, per se, related to the rental program, the Board believes that there should be some recognition of the benefits they have received in the past. The Board therefore would accept the provision of a notional utility account in the amount of $50 million, after tax, to allow the shareholder to use the value of these past ratepayer benefits to pay a portion of the deferred taxes associated with the rental program as they become due." 40 That, Mr. Chair, is the genesis of the notional utility account from which the company proposes to draw. One reason why I bring this to the Board's attention is that the original point of the account was that the Board made a finding that ratepayers had benefited from the rental program before it was unbundled from the utility and the Board specifically said that there should be some recognition of those benefits. That was the original basis of the notional utility account. 41 Subsequently, and that being December 2003, the Board issued a further decision regarding the circumstances in which the company can draw on the notional utility account. That was in the RP-2002-0135 proceeding and the decision is at tab 2 of Exhibit K.13.1. I don't know that you need to turn it up now. I will be coming to this in much more detail later in my submissions. Again, just to indicate where the item at tab 2 comes from, the record in this case, it is found in Exhibit K.7.2, at tab 9. 42 In summary, and again I will come back to the words of the decision, the Board determined in this proceeding that the company is entitled to recover from the notional utility account an amount after taxes equal to the deferred taxes that became payable between the date when the rental program assets were transferred out of the company and the date of May 7th, 2002. 43 The company has determined the amount of deferred taxes that became payable in that time period identified by the Board and the amount is 23.9 million. That's not in the brief. The reference for that is Exhibit A8, tab 5, schedule 1, page 1. 44 Now, in light of the December 2003 decision about what could be recovered from the notional utility account and the company's determination that that amounted to $23.9 million, the remaining amount of the account had to be written off by the company. That was a remaining amount of approximately $26 million. What happened was that a $26 million charge to the company's income statement was taken in December 2003 as a result of the Board's determination regarding what could be recovered from the account. The reference for that is volume 11 of the transcript, paragraphs 59 to 64. 45 This leaves the $23.9 million, after taxes, in the notional utility account that the company proposes to recover over two years. This represents the deferred taxes payable over the time period that the Board identified in its RP-2002-0135 decision. 46 That, I think, Mr. Chair, summarizes the nature of the company's position regarding a drawdown of the notional utility account. I would like to now come to some of the issues about deferred taxes, but in order to do so, I think it's very important that I set some background with some general comments about deferred taxes. 47 During his testimony, Mr. Boyle explained the concept of deferred taxes and in doing so he provided an exhibit which was marked as Exhibit K.7.1. That is found at tab 3 of the brief that is Exhibit K.13.1.. As Mr. Boyle explained, and as is shown in Exhibit K.7.1, deferred income taxes arise because of differences between depreciation for accounting purposes and capital cost allowance, which is a tax type of depreciation, capital cost allowance for tax purposes. As Mr. Boyle explained, the Canada Revenue Agency allows rates of CCA that exceed accounting depreciation rates in order to encourage capital investment. In this regard, the Board will recall that Mr. Boyle used the analogy of an interest-free loan from the Canada Revenue Agency when he explained the concept of allowing CCA deductions to be greater than accounting depreciation. 48 For simplicity in my submissions, I will use the term accelerated write-offs. I can't say whether that's a tax person's term because I'm not a tax person, but in my mind, the words "accelerated write-offs" capture the notion of what the Canada Revenue Agency allows to happen by way of CCA. 49 In my submission, and we will look at Exhibit K.7.1 to see this, what is important to understand is that although CCA allows accelerated write-offs, in the case of any single asset as opposed to a changing pool of assets, the amount that is written off for either purpose - either CCA or accounting depreciation - is ultimately the same. It's ultimately the book value of the asset is the maximum that can be written off under either CCA or accounting depreciation. So in using the phrase accelerated write-offs, I'm trying to capture the notion that there is more write-off for CCA in the early years of the life of a particular asset, but because the same amount is written off for both accounting depreciation and CCA over the whole life of the asset, ultimately accounting depreciation overtakes CCA in the case of a single asset. And we can see this from Exhibit K.7.1, if the Board were able to turn up tab 3 of Exhibit K.13.1.. 50 Now, looking at Exhibit K.7.1, from lines 8 to 11, the concept of accounting depreciation is presented. At line 9, we can see that the book value of the capital asset being used here is $250 for accounting depreciation. If we then go down to line 10 to see what happens from an accounting point of view by way of depreciation, and if you go across line 10 from year 1 to year 6, you will see that the entire $250 is written off, the entire value of the asset from years 1 to 6. As I said, whether it's accounting depreciation or CCA, that's the most that can be written off. 51 Now, if one compares that to what happens with tax depreciation, from lines 12 to 16, one can see at line 14 the same capital asset book value of $250, but then for tax depreciation purposes, that being CCA, at line 15, the same amount is written off, $250, it just happens much more quickly, it happens from years 1 to 3. So this is why I've used the term accelerated write-offs. The same write-off occurs for accounting depreciation for tax purposes, it's just faster, accelerated, in the case of taxes. And I will, of course, be coming to explain why I consider this to be important in the context of this case. 52 Now, the other effect of this, as I've already alluded to, is because CCA is written off in an accelerated basis in relation to accounting depreciation, in the early years CCA exceeds accounting depreciation, but ultimately, that flips to the reverse so that depreciation is exceeding CCA. The word crossover has been used in the evidence in this case. It's in some of the items I've included at K.13.1. Crossover has attempted to capture that point in time where instead of CCA exceeding accounting depreciation, the reverse comes true and accounting depreciation is exceeding CCA. So that crossover point again, if we are comparing depreciation at line 10 to capital cost allowance at line 15, one can see for each of the first three years, capital cost allowance is greater than accounting depreciation, but then for the next three years the reverse is true. And this is the impact of the accelerated write-offs of CCA in the early years. 53 Now, this is the effect with an individual asset. As I've already alluded to, of course, if there's a changing pool of assets, the effect of continuing to add new assets to the pool, and therefore continuing to achieve more accelerated write-offs, may be to push off into the future the point when this crossover for the pool as a whole will occur. But the point here is to compare what happens before crossover to what happens after crossover. 54 Before crossover, the company has less taxes payable than would otherwise be the case because of the accelerated write-offs, and we can also see this from Exhibit K.7.1. What we need to do here is to compare lines 19 and 20, which are the accounting basis, to lines 23 and 24, which are the tax basis. 55 Looking at years 1 to 3 and comparing line 19, which is the accounting basis, to line 23, which is the tax basis, what one will see is that in each of those three years, accounting income is higher than taxable income, so that's line 19 compared to line 23, years 1 to 3. This is the effect of the accelerated write-offs. Accounting income is higher than tax income in each of those three years. And then looking at line 20 for each of those three years, the effect is that what Mr. Boyle has called accounting income tax at line 20 is higher than what he's called Canada Revenue Agency income taxes at line 24 for each of those three years. 56 So the effect of the accelerated write-offs is to reduce taxes otherwise payable before crossover, and that is in fact the deferred taxes, that reduction. But this reduction in taxes payable by reason of deferred taxes is not the same thing as this entity's actual cash taxes payable. This entity might well have other activities, other earnings, other tax deductions, and so on, that affect actual cash taxes paid. The effect that one sees with respect to the deferred taxes having an impact on taxes payable is not necessarily the same impact on cash taxes actually paid because cash taxes actually paid will bring in all the other things that are relevant to the tax position of the particular entity. 57 And then after crossover, the reverse is true. And again we can see this by comparing the same lines that we just looked at but for the years 4 to 6. So comparing line 23, the income for tax purposes, to line 19, the accounting income, in years 4 to 6, we now see that the reverse has come true. Income for tax purposes is higher than accounting income in years 4 to 6. Comparing lines 24 to line 20, what Mr. Boyle has called Canada Revenue Agency income taxes, are higher than what he has called -- at line 24, than what he has called accounting income tax at line 20. This is the deferred taxes becoming payable. This is what is depicted here after crossover. Because Canada Revenue Agency income taxes are now higher than what income taxes would be according to the company's books, the deferred taxes are becoming payable after crossover. 58 But, again, "payable" in my submission is the important word here. The deferred taxes that are becoming payable because of this effective crossover are not at all the same thing as this entity's actual cash taxes paid. Again, the same is true after crossover as before crossover. This entity may have other earnings, other activities, other tax deductions that are going on after crossover and that affect actual cash taxes paid. However, whatever those may be, the fact still remains that the deferred taxes are becoming payable in the years 4 to 6. 59 The point is that the deferred taxes becoming payable are not a function of other things going on in this company, they are a function of accounting depreciation at this time now overtaking and exceeding CCA. And I can spend more time working through the numbers and showing how accounting depreciation, because it exceeds CCA, makes the income for book purposes less than what Mr. Boyle has presented as taxable income, but I won't spend more time on the numbers. The point is simply that what is driving the deferred taxes becoming payable is accounting depreciation exceeding CCA in this period after crossover. This is happening independently of other things going on in this entity which, in my submission, would be irrelevant to a determination of deferred taxes becoming payable. 60 MR. SOMMERVILLE: Mr. Cass, just on that point, that is true so long as there are no additions or growth within the assets -- 61 MR. CASS: That's correct. 62 MR. SOMMERVILLE: -- that give rise to the depreciation accounts. Is your view the same if -- does your position only prevail if there are no additions to this account? 63 MR. CASS: You're quite right, Mr. Sommerville, that this analysis is looking at it on the basis that it is a static asset or pool of assets. As I will come to later in these submissions, I will be saying, first of all, that this very point as to whether the rental program assets that were unbundled from the utility and that had these deferred taxes associated with them should be viewed in that way, it would be my first submission that that was actually addressed in the -- I'll just get the number right -- 64 MR. SOMMERVILLE: I don't want to interrupt the timing that you have, but I just wanted to clarify that point, that as we look at this account, you are saying that this is the account, assuming that it's static. 65 MR. CASS: That's correct. And I guess the effect of the submissions that will come later, Mr. Sommerville - it is a good question and the timing was very good because I can summarize it - the effect of the submissions that will come later, in light of the EBO 179-14/15 decision, and even more particularly the 2002-0135 decision, that's the way these rental program assets should be viewed for the purposes of determining deferred taxes payable; that it is inappropriate to sweep in other asset acquisitions that were not part of the original unbundled rental assets. And so I will be addressing that in more detail, but your question was a timely one. 66 So, in fact, this does bring me now to addressing what was considered by the Board in its December 2003 decision in RP-2002-0135. I think it's important to do this for two reasons; first, just so that we all understand what was at issue and what was determined in that decision; also I think it's important because in some of his preemptive arguments, Mr. Thompson has already made a submission to the Board about what was considered in that decision and attempted to, in my view, narrow it to something much less than it actually was. So I think it is very important that we all appreciate what was considered in the 2003 decision. The comments by Mr. Thompson that I'm referring to, by the way, were at volume 7 of the transcript, at paragraph 190. 67 When Mr. Thompson started this submission that he made at that time, where he tried to narrow the effect of the 2003 -- December 2003 decision by reference to a motion record that had been filed by his client and a couple of other intervenors quite a long time before the December 2003 decision, what Mr. Thompson referred to was Exhibit K.7.3, a motion record of moving parties IGUA, CAC, and VECC. This related to a motion that those parties brought in connection with the notional utility account. 68 This motion record has at the front of it a notice of motion, which we will come to. It's dated May 2002. I just point that out by way of explanation of my submission to the Board that this actually was far, far in advance of the December 2003 decision. 69 But what Mr. Thompson said to this Board Panel during this case about when he was referring to this motion record was that during the determination of the 2002-0135 case, there was no evidence before the Board about transactions that took place following October 1, 1999. Again, the transcript reference for that is volume 7 of the transcript, paragraph 190. I think it is quite important to set the record straight on this and as a result I've included some excerpts from that motion record, K.7.3, in the brief, which is K.13.1. 70 At tab 4 of K.13.1, I've included the notice of motion from the motion record that, in this case, is K.7.3. Now, I won't go through all of the grounds in this notice of motion because if the Board turns it up and looks at it, you'll see that the grounds start at the bottom of the first page of the notice of motion and they continue all the way over to page 5 of the notice of motion. That's how many grounds there were presented by these parties in connection with the issues they raised about the notional utility account at that time. However, I won't go through them all, but I will just try to highlight a few of them to, again, get across to the Board how much was at issue and brought forward by these parties for determination at this time. 71 If the Board could then look at page 2 of this notice of motion, and again I'll just pick out a few of these grounds, ground F on page 2 talks about the transfer of the rental program to an affiliate and the sale to Centrica for what's called here a gain of -- net gain of $210 million. There is the sale to Centrica that this Board has heard about in this case. I'll just skip through some of these. 72 Ground H, if you look at it, talks about how, on December 23rd, 1999, the owner of ESI restructured its arrangements and made the transfer of assets to 3696669 Canada Inc. That numbered company has been referred to in this proceeding as Rentco so I will, for convenience, refer to as either Rentco or the numbered company. Ground H in this notice of motion is the transfer of the rental program assets to Rentco which the Board has also heard about in this proceeding. 73 Flipping over to the next page, there are a series of points, grounds I, J, and K, that have to do with taxes payable within ESI, that is, Enbridge Services Inc., notwithstanding the transfer of the rental program assets to Rentco. Grounds I, J and K, in my submission, essentially constitute the same argument the Board is hearing in this case, that for the purposes of determining deferred taxes payable, one has to put together the assets of ESI with the assets of Rentco. In my submission, that's really what I, J and K are all about. 74 Grounds L and M, you will see, have to do with increase in rental program rents that occurred after the rental program was unbundled by the utility and was being operated as an unregulated program. I think these were also alluded to in this case. 75 And ground N is the sale to Centrica, again referred to in this case. 76 I won't go on with all of the grounds, but my point is just to bring out the breadth of what was put before the Board in this motion. And also, again, to set the record straight in relation to this comment that the Board had no evidence when that motion was brought by the moving -- by those moving parties, certain intervenors. Also in Exhibit K.7.3 was an affidavit by Mr. Fournier in support of the notice of motion that I've just shown the Board. This affidavit is at tab 2 of Exhibit K.7.3 and I've just included some extracts from it at tab 5 of today's brief, Exhibit K.13.1.. 77 The point is that if you look through this affidavit in its entirety, you will see that Mr. Fournier, in fact, provided evidence on the grounds set out in the notice of motion. Indeed, this is only what one would expect because IGUA could not bring a motion asserting all of the grounds that I've referred to without being satisfied that it had supporting evidence on these grounds. So, again, I don't intend to spend a lot of time on it, but just quickly looking at some of the items in the affidavit from Mr. Fournier that I've included at tab 5 of today's brief, there's a page with a black number 11 at tab 5, and under heading D, paragraph 10, the Board will see detailed evidence about transfer of the rental program assets to Enbridge Services Inc., including dates and numbers of customers and so on. Then the next page I've included is numbered as page 13, at tab 5, under the heading G, Reaction to RP-1999-0001 decision, "Restructuring of Ownership of Rental Program Assets," the transfer of assets to Rentco is addressed and evidence is given in that regard. 78 At the next page that I've included, and again, these are just extracts from the affidavit, the next page I've included is number 14, and you'll see there evidence about these rent increases that are said to have occurred after the unbundling of the business from the utility. 79 The final page I've included is page 15, which gives evidence about the sale of the rental business to Centrica, the amount of the net gain, various other dollar figures and so on. 80 Now, what I would also like to do is just take a little bit of time to track through what happened with these issues raised by these intervenors up to and including the Board's decision in the 2002-0135 proceeding. So for that purpose, I've included some other items in Exhibit 13.1 which can be found at tabs 6, 7, and 8. 81 These items, just to identify where they came from in the record, were part of a documents brief that IGUA submitted in this case. It was given Exhibit K.7.2 in this proceeding. It included argument in chief of these intervenors in the 0135 proceeding. That was at tab 6 of Exhibit K.7.2, and as it happens, extracts from it are at tab 6 of Exhibit K.13.1.. The company's responding argument provided by IGUA was at tab 7 of Exhibit K.7.2, and extracts are at tab 7 of Exhibit K.13.1.. And finally, this group of intervenors had a reply argument which was at tab 8 of Exhibit K.7.2, and extracts from that are at tab 8 of the new brief. 82 Taking, for example, the issue of the sale to Centrica that has been alluded to by intervenors in this proceeding, this issue was addressed in argument in chief by IGUA and the other intervenors in the 0135 proceeding and we can see this at tab 6 of Exhibit K.13.1.. Again, I've just included some extracts here to expedite the argument, but if one were to look four pages in at tab 6, one would see page 14 from the argument in chief of the intervenors in that other proceeding. And at paragraph 29, one will see the argument about the sale to Centrica and the premium, what's called here the premium over book value of some $210 million and so on. 83 The point is also made in this same argument in chief at paragraph 79. I'm sorry, in my book, Mr. Chair, the last two pages at tab 6 of the brief got switched. I'm not sure if that's the case with everybody's book. But paragraph 79 can be found on page 36 of this argument in chief, which should be the second- last page. It may appear as the last page. 84 So at paragraph 79, you'll see the same argument that a completion of the sale to Centrica eliminates the exposure to deferred taxes liability because $210 million exceeds the $50 million in the notional utility account. 85 Now, the company responded to this submission in the 0135 proceeding, and I've included extracts from the company's responding argument at tab 7 of the brief. The extracts I've included are the front page of the company's argument and pages 12 to 14. The sale to Centrica point is addressed by the company starting at page 13. I won't take the Board through all of these submissions, but just really to exemplify, if I could, the company's response to what intervenors were saying, there's a paragraph on page 14, it's the last full paragraph on that page and perhaps I might just quickly refer to that. This paragraph starts out: 86 "The sale to Centrica relied upon by IGUA, CAC and VECC was a transaction between companies that are not regulated by the Board. It included other businesses and assets in addition to the assets that formerly comprised the Company's Rental Program. It was completed approximately two-and-one-half years after the Company unbundled its ancillary businesses including the Rental Program. The evidence about the transaction brought forward by IGUA, CAC and VECC indicates that the sale proceeds reflected value created in the businesses by Enbridge and that the value was increased after the unbundling from the Company." 87 And the reference to the affidavit of Peter Fournier for that is provided. So I won't go on, but I think that just exemplifies the nature of the response that the company made in that case to the submissions about the sale to Centrica. 88 Then the intervenors had a reply argument on this point, which is at tab 8 of today's brief, and I won't go through this at all except just to point out how lengthy it was. It starts at page 26 of the extract that I've provided at tab 8. This is under the heading "Consideration of the Proceeds of a Sale." And the Board can see that these intervenors' reply argument on the point that the proceeds of the sale should be considered went from page 26 to 29 of this reply argument. 89 So that sets the background for one issue that the Board was deciding in the 0135 case, and with that background I'd appreciate it if we could actually turn up the Board's decision in 0135, and that's at tab 2 of Exhibit K.13.1, the small brief from today. The decision on this would be two pages from the back of tab 2. Actually, I don't know that we need to turn it up, but just by way of reference, in this decision the Board did refer to the company's argument with regards to the sale to Centrica, that's at paragraph 25, and the Board did refer to the intervenors argument about the sale to Centrica, that's at paragraph 43. So the Board was definitely considering this issue. 90 The Board's decision, in my submission, on this issue appears at paragraphs 61 to 62 which are, as I said, the second last page from the back of the tab. So at paragraph 61, the Board said: 91 "The rental program assets have been sold to a third party. As such, neither EGDI nor its affiliates bear any further tax liability post the date of the sale in relation to those assets. The Board finds and orders that EGDI is entitled to recover from the notional utility account an amount, after taxes, equal to the taxes that became payable between," and I'm skipping some words here "the date to when some assets were transferred out to the affiliate and the date of the sale to the third party." 92 So having heard all these arguments about the sale to Centrica, what the Board drew from this was that neither Enbridge Gas Distribution, nor its affiliates would bear any tax liability beyond the date of the sale, and the Board determined that Enbridge Gas Distribution could recover an amount, after taxes, equal to deferred taxes payable up to the date of the sale. The Board treated the sale to Centrica as relevant to setting the cutoff date, so it's for the recovery of deferred taxes that became payable. The Board did not accept the intervenors' argument that the sale to Centrica had any other consequences for deferred taxes recovery. 93 Now, there are many issues raised in this other proceeding, and I've alluded to one of them, which is IGUA's point about rental rates being increased after the unbundling of the rental program from the utility. I won't attempt to address all of these and show how they were all dealt with in the 0135 proceeding. The other point is this notion about when considering when deferred taxes became payable, one should combine together in some fashion ESI, Enbridge Services Inc., rental assets with Rentco rental assets and make the determination on that basis. The submission that this Board has heard is that somehow tax deductions that might have been available or tax savings that might have been available within Enbridge Services Inc. should somehow be relevant to taxes payable within Rentco. Well, in my submission, this was another argument that was already determined by the Board in the 0135 case. 94 Now, again, if we could go back to tab 6 of K.13.1, just to track through some of the arguments on this, in argument in chief by the intervenors, that's at tab 6, the point was raised at paragraph 58, that's page 27 of the extracts that appear at Exhibit K.13.1 -- I won't read all of paragraph 58, but it refers to expert advice that IGUA says it had received indicating that had the rental program remained with ESI after October 1, 1999, then little or none of the unrecorded deferred taxes would likely have become available before May 7th, 2002. And then there's another reference to the sale to Centrica. And then skipping to last sentence at paragraph 58: 95 "The expert advice that IGUA has received indicates that any taxes payable by Enbridge Canada," that's what we're referring to as Rentco or the numbered company, "will be offset by tax savings associated with capital cost allowance claimed on equipment acquired by ESI." 96 So this is the same point we're hearing in this case about offsetting ESI tax savings or tax deductions with the tax position of Rentco. 97 Just to complete the record, it was also addressed in paragraph 81 of this argument in chief, but I don't think that we need to go into that much detail. 98 So this issue about combining, if I can use that word, the tax results of ESI with Rentco was responded to by the company in its argument in the 0135 case. That's also at tab 7 of Exhibit K.13.1, starting at page 12, under the heading "Transfer of Rental Program Assets." 99 This comes back, Mr. Sommerville, to the point I was making earlier in response to your question about why is it appropriate, for the purposes of looking at deferred taxes that became payable, to treat the rental program, unbundled from the utility, as a static pool of assets. This is what the company addressed in the argument we're now looking at and ultimately this is what I submit the Board decided in the company's favour in the 0135 case. So it's addressed in some detail on pages 12 to 13 of the submission at tab 7. I don't want to read the whole thing, but perhaps again I could just read some parts to give a flavor of the company's position as to why the unbundled assets -- what constituted the original rental program within the utility is what is relevant, not other assets acquired by unregulated businesses at some time after the unbundling. 100 So just starting with the last paragraph on page 12 of this submission, it's responding to a point by the intervenors that by putting the rental program assets into Rentco, that that was somehow artificial. The Board will see there the submission: 101 "In the context of the 179-14/15 decision, there was nothing artificial about winding down, within Enbridge Canada," that's Rentco, "the rental program formerly operated by the company." 102 And I should point out here that the importance of winding down is that it brings into effect crossover, the importance of crossover, as I explained at the opening of my submission, is that that's what triggers deferred taxes becoming payable. So the submission goes on to say: 103 "A central underpinning of the 179-14/15 case was the company's proposal to wind down the rental program. The company's proposal explicitly contemplated that as the program wound down there would be an orderly transition of customers to competitive supplies (one of which could well be an affiliate of the company.) When the Board discussed a wind down in 179-14/15, it was referring to a wind down of the rental program operated by the gas distribution utility, not a concurrent wind down of any and all equipment rental activities that might occur within the Enbridge organization." 104 Then just skipping down another sentence: 105 "The Board did not say or suggest that equipment rental initiatives by affiliated companies would affect any drawdown of a notional utility account to offset rental program deferred taxes, even though it went on to postulate that the options available to the company included a transfer to an affiliate or a sale to a third party." 106 And then there's a further submission I would like to touch on. 107 "The company submits that it is logical that the 179-14/15 decision approached the subject of deferred taxes in this way: Any affiliate of the company with active business operations would have its own set of tax credits or tax liabilities or the potential for creation of tax credits or liabilities. These tax credits or liabilities would be to the affiliates' own account, absent the transfer of rental program assets, they should be no less to the own affiliates' own account upon a transfer of rental program assets." 108 I won't read any more. That's part of the company's submission about why it was perfectly appropriate to have the assets in Rentco and to deal with them in the fashion that was done as the Board is aware from the record of this case. 109 Now, again, there was a lengthy reply argument from the intervenors on this issue about combining ESI tax savings, if any, with taxes payable by Rentco. I've included this at tab 8 of the small brief. Starting at page 23, there's a large heading "Recoverable Amount of Any Taxes Paid," and then a smaller heading, "Taxes Payable by EI's Rental Equipment Business." That argument goes on from page 23 over to page 26, and in my submission it's, again, the argument that the Board is hearing in this case about combining ESI and Rentco. 110 Now, once again we can look at how the Board treated this argument in the 0135 decision. That is at tab 2, as I've said, and again the actual Board decision is two pages back from the end of that tab. This time it's paragraph 60 that's relevant. Looking at paragraph 60 in the 0135 decision at tab 2, the Board says: 111 "The intervenors argued that EGDI's ability to draw on the notional utility should be limited to the amount which would have been payable in taxes had the assets been kept within the first affiliate and operated on an ongoing basis rather than transferred to a second affiliate and operated on a wind-down basis. In our view, the language in the Board's EBO 179-14/15 decision does not support this interpretation. This interpretation would preclude, in effect, EGDI and its affiliates from engaging in normal tax planning in order to optimize exposure to deferred tax liability. In fact, one of the options identified by the Board in the EBO 179-14/15 decision specifically contemplates transferring the rental program assets to an affiliate or selling to a third party." 112 In my submission, this is reflective of the points from the company's argument that I took the Board to at tab 7 of this brief. So it is most certainly true that the Board did not accept all of the company's arguments in the December 2003 decision. As I've already discussed, the company wrote off to income $26 million because of the Board's decision about what could be recovered from the notional utility account. But in my submission, the Board did accept this point from the company, first of all, that the point about combining the assets of ESI and Rentco for tax purposes was not appropriate; and secondly, the Board accepted, in my submission, the company's point about being able to do tax planning. 113 Sorry, Mr. Sommerville. 114 MR. SOMMERVILLE: You anticipated my question, Mr. Cass. Paragraph 60 of the decision in 0135 is the one that you've just referred to and it addresses this question in saying, and I'm quoting from the decision: 115 "This interpretation would preclude, in effect, EGDI and its affiliates from engaging in normal tax planning in order to optimize exposure to deferred tax liability." 116 Should we read optimize tax liability to mean resting tax liability with one of the affiliates -- one of the companies, EGDI in this case, and holding the others -- optimizing their liability? Do you see my point? 117 MR. CASS: I do see your point. 118 MR. SOMMERVILLE: Optimizing tax liability, it seems to me, suggests taking prudent steps to reduce overall tax liability but not necessarily stick-handling liability from one to another within that group of companies. 119 MR. CASS: I understand your point completely, Mr. Sommerville, and it was certainly a question that crossed my mind. And the reason I interpret the sentence the way I do is the context, because the whole context of the Board saying this is addressing what the intervenors had called this artificial placing of assets in Rentco, so that's the first sentence of paragraph 60, and it's in that context that the Board is talking about EGDI and its affiliates being able to optimize exposure. So in my submission, when you take it in its context, it is talking about the first thing that you described, the course of action that the company or its affiliates took when the assets were moved into Rentco and the things that flowed from that, because that is the very context of what the Board is considering in paragraph 60. 120 MR. SOMMERVILLE: Just on this point, let me ask one further question and it relates to the original decision that the Board made in 179-14/15. Yes. That's at tab 1 of your materials. And, of course, this is the seminal document, I suppose. But there's a reference in here or throughout this decision to the rental program, and this is language that's used by all of the documents going forward. One way of looking at that language is to say that the rental program consisted of the rental program and it consisted of, however the ownership of those assets was altered, the rental program continued. The rental program was a combination of the original assets that were ultimately sold and then leased back and the new assets that were used as part of the rental program. What's your response to that characterization? 121 MR. CASS: Yes, that's, I think, also a very important question, Mr. Sommerville. 122 I believe that the company has always tried to be very consistent when addressing this deferred taxes issue over the years, to speak of the rental program as being the assets that were formally in the utility that were unbundled and often the company has capital R and capital P on rental program, and in my view, the point of that is to try to make very clear that the rental program that the company is discussing is those assets. 123 In this case, as I recall, there was some other terminology used, again, to try to make it very clear that that's the company's view about what was in issue. I think the terminology was transferred rental assets or transferred assets, something like that. Again, trying to get across the company's point that what is really relevant is the assets that came out of the utility. 124 Now, it is definitely true that in at least one if not more places in the intervenors' submissions, they've then taken that rental program, capital R, capital P, and tried to imply that it includes other assets acquired later by an unregulated affiliate. That is not how the company uses the words rental program. When the company uses those words, it is intending to talk about the assets unbundled from the utility, and there is a very good reason for this which Mr. Boyle explained, and I won't be able to do it as well as he did, so I'll just have to refer you to Mr. Boyle's testimony in the transcript. 125 The point is this: The rental program assets are a group of assets that have associated with them, wherever they lie, costs and benefits. That's how Mr. Boyle described it. And I might also add risks. Any business, any set of assets has costs, benefits, and risks associated with it. One of the costs or disbenefits associated with that group of assets is the deferred taxes that had accumulated while they were within the utility. It's the company's point that those are the deferred taxes that are relevant. When it's unbundled and those deferred taxes become payable, that's what's relevant. Other assets, other businesses, other activities within the unregulated companies may also have benefits in the form of tax savings, but they also come with costs and risks. So the point Mr. Boyle was making is it's quite unfair for the purposes of looking at the deferred taxes payable in respect of that group of assets that came out of the utility to then say, We're now going to grab some of the benefits associated with some unregulated assets, those benefits being tax savings, and we're going to apply those, because it is -- it's what Mr. Boyle called a mismatch. It's taking benefits that the shareholder has associated with its activities and its assets while at the same time the shareholder still holds whatever risks, costs, disbenefits are associated with those same unregulated assets. 126 So that was the point Mr. Boyle was trying to make. I was going to come to this later. But that's the company's point about why it is so important to remember that the rental program assets are those that were transferred out of the utility, and the deferred taxes payable are the taxes that were associated with that group of assets, so it's not some other group of assets. And Mr. Boyle with his mismatch analogy perhaps put in better than I've done and that the company did in its argument, but the company was trying to make the same point in the 0135 proceeding in the extracts that I took the Board to. Remember, without turning up tab 7 again, the point being made there was that the fact that the unregulated businesses may have some tax savings or tax benefits, they would have those for their own account anyway and so when the rental program assets are transferred out, to then say that we're going to grab those and use those against the deferred taxes payable on the rental program assets is quite unfair to the shareholder of the unregulated businesses because it's using up benefits or tax savings that would have been there anyway for the shareholder to enjoy on an unregulated basis. So it's the same point that was being made in the 0135 case in the argument that I showed you, and in my submission it was decided by the Board, and that was the wording in paragraph 60. 127 MS. NOWINA: Mr. Cass, then to go back to the decision 179-14/15, the reference you referred us to where the Board believes there should be some recognition of benefits, so is the position of the company, then, that the costs that you're discussing related to these particular assets are related to these benefits that the Board recognized in that decision? 128 MR. CASS: That's exactly it, Ms. Nowina. Thank you. Again, that's Mr. Boyle's matching or mismatching -- 129 MS. NOWINA: That's what he's trying to match, those benefits to those costs. 130 MR. CASS: That's right. The Board was, I believe, trying to do a matching in EBO 179-14/15 EBO 179-14/15. It says some recognition needed to be given to these benefits, and so it matched those benefits against the deferred taxes payable in relation to the rental program that was under consideration in that case. That's what those benefits were matched against. 131 MS. NOWINA: And you see that specific to those assets that were later pulled out and put into Rentco. 132 MR. CASS: Correct, because it was those assets that had delivered the $50 million of benefits to the ratepayers. I didn't include it in here, but the Board actually did a calculation in the EBO 179-14/15 case to come up with the number of $50 million after tax that those assets, the original rental program assets, had delivered to ratepayers. It's not benefits that were delivered by some assets in an unregulated company. So yes, that is the matching of the deferred taxes in relation to the rental program assets originally within the utility to the benefits that those same assets had provided in the order of $50 million to ratepayers. Thank you, Ms. Nowina. 133 MR. BETTS: I have one question too, and we may have kind of concluded all of your arguments with these questions. 134 MR. CASS: This does cover much of what I was going to say. 135 MR. BETTS: This one relates to what you said that the company shouldn't be, and I'm paraphrasing me, and correct me if I've paraphrased incorrectly, but the company shouldn't be penalized as a result of having used some of its potential benefits in other portions of its corporation by reducing the taxes in this situation. How would you respond or how would you address the question that might be posed as to -- or if someone -- if someone argued that those could not have otherwise been claimed, those benefits could not have otherwise been realized had it not been as a result of this transaction, how would you address that? 136 MR. CASS: Well, if that argument were to be made, Mr. Chair, I don't believe it would be factually correct. Now, I'd have to go back and check the transcript to see what Mr. Boyle would have specifically said to address that. But it's certainly not my understanding that there would have been any inability to realize those benefits that were otherwise available to the unregulated companies in the absence of the transfer out of the rental program. That's not my understanding at all, that those benefits could not have been realized. And in the event that it is posed in anybody else's argument, I will check through the transcript of what Mr. Boyle said to see if I can find a reference to that particular point. 137 MR. BETTS: Thank you. I think you can go ahead with your argument. 138 MR. CASS: Yes. As you did say yourself, Mr. Chair, that does cover a lot of things that I intended to say, so I'm just going to take a moment here to look through my notes and try to reduce some repetition that will occur if I proceed the way I was intending to. 139 MR. BETTS: Go right ahead. 140 MR. CASS: So I did have submissions -- some submissions here about Mr. Boyle's testimony on this concept of matching, and again I have really, I think, made the point. If I could just do two things to wrap up on that point. 141 First of all, I think there are probably a number of transcript references where the Board can find what Mr. Boyle said on this, but one, if the Board wants to look for it, is at volume 8 of the transcript, paragraphs 114 to 116. And the only other elaboration I would like to add to the point is to just make clear that it applies in a couple of respects. It applies, first of all, in respect of the tax planning that intervenors have attempted to make relevant in this case, just general Enbridge Inc. tax planning. Mr. Boyle's testimony, I believe, is that to apply the reduction in cash taxes paid by the legal entity as -- the legal entity being Rentco, as a result of non-utility, non-regulated transactions to offset a utility cost would offset this matching that Mr. Boyle talked about. 142 So, first of all, it's to use these benefits from tax planning to offset the deferred taxes payable would violate the matching principle. 143 And then the other point is it also applies in respect of trying to put together the tax impact of ESI with Rentco also violates the matching principle, and I think I've already addressed that in some detail. 144 So it's two separate things. It's the tax planning within Rentco, is really -- should not be -- should be quite independent of and irrelevant to the deferred taxes that became payable, and also what happened in ESI and the asset acquisitions there should be quite independent of and irrelevant to the deferred taxes that became payable. For all the reasons I already discussed, but I just wanted to indicate that it really applies to two different things. 145 And this also brings us right back to the submissions I started with, which I won't repeat in any detail, which were that deferred taxes becoming payable are a function of really one thing and that's accounting depreciation in respect of that particular group of assets reaching a point in time where it exceeds CCA. That is what causes deferred taxes to become payable. This is quite independent of other activities, in this instance other unregulated activities, that may affect cash taxes actually paid. 146 In my submission, this was part of the point that the Board was accepting in the 0135 decision in that paragraph 60 that we've looked at, again, when paragraph 60 is considered in the context that it was addressing. 147 The other thing that's interesting about the December 2003 decision, when one thinks about how deferred taxes become payable and the difference between deferred taxes becoming payable and actual cash taxes paid, is that the Board clearly and repeatedly in the December 2003 decision uses the word "payable." As far as I know, it doesn't at any time refer to cash taxes actually paid which it could have easily done if it had that in mind. 148 Just by way of some examples, again at tab 2 of Exhibit K.13.1, the same page that we looked at a number of times, two pages from the book, there are several examples of what I've just said. At paragraph 58, for example, the concluding sentence talks about what can be recovered from the notional utility account, and it says: 149 "Recover from the notional account only as deferred taxes became payable and only up to $50 million after tax." 150 Same thing at the end of paragraph 59: 151 "Conditional upon deferred taxes associated with the rental program becoming payable." 152 Same thing in paragraph 62: 153 "An amount after taxes equal to the deferred taxes that became payable." 154 If what the Board had in mind was actual cash taxes paid, it would have been the easiest thing in the world for the Board to have said so. In my submission, the Board repeatedly used the word "payable" for very good reasons and the reasons have to do with what I've attempted to explain in my submissions about how deferred taxes become payable when accounting depreciation exceeds CCA and how that is quite independent of other things that may affect cash taxes actually paid. 155 In my submission, the Board stayed away from cash taxes actually paid, which would have perhaps have been an easier concept, and advisedly used the word "payable" because that is the appropriate word. 156 In conclusion, the Board said in the 0135 decision that this amount of deferred taxes payable within the time period identified by the Board could be -- that Enbridge could seek to recover that amount appropriately verified in its next rate application. In my submission, that's precisely what the company has done. The company engaged KPMG to verify the deferred taxes that became payable up to May 7th, 2002. This was specifically in response to the Board's indication that the amount should be appropriately verified. This verification is found at Exhibit A8, tab 5, schedule 1 appendix, and the company has requested recovery on an after-tax basis of the verified amount over two years. 157 That completes my submissions, Mr. Chair, unless there are further questions. 158 MR. BETTS: I'll just confer for a moment. 159 [The Board confers] 160 MR. BETTS: Thank you, Mr. Cass. There are no further questions on that portion of the argument. 161 MR. CASS: Thank you, sir. 162 MR. BETTS: Ms. Persad, I'm just wondering whether it would be appropriate to take a break at this point. 163 MS. PERSAD: I was going to suggest that five minutes would be fine with me, Mr. Chairman. But if you would like to take a longer break. 164 MR. BETTS: Well, let's make it 15 minutes and we will aim to be back, then, at 10 minutes past 11. Thank you. 165 --- Recess taken at 10:58 a.m. 166 --- On resuming at 11:13 a.m. 167 MR. BETTS: Thank you. In the interests of time, we will proceed, Ms. Persad. I assume that there were no preliminary matters that arose during that short break? 168 MS. PERSAD: No, Mr. Chairman, there weren't. 169 MR. BETTS: Thank you. Would you please begin your arguments on your portion. 170 MS. PERSAD: Yes, I will, Mr. Chairman. Thank you. 171 SUBMISSIONS BY MS. PERSAD: 172 MS. PERSAD: I am going to address three issues, as Mr. Cass alluded to, and the order in which I am going to address them are first to deal with issue 5.1, the Union Gas storage contract; second, to deal with the rate design issues, issues 15.1 and 15.2; and thirdly, to deal with issue 11.2, the subset of that issue being the 2005 class action suit deferral account. 173 So to begin with the Union Gas storage contract, and I'll just say as a preliminary matter, Mr. Chairman, I did not prepare a brief of evidence like Mr. Cass did for the deferred taxes issue and I did that deliberately because in my argument in chief, I am not making any references to complicated or complex or particularly controversial items in the prefiled evidence. However, if the Board wants to have before it the materials to which I'll largely being referring, I would ask you to have before you for this issue Exhibit A3, tab 2, schedule 5, and that was the evidence upon which the company's submissions are mainly based for the Union Gas storage contract, and for this issue also, transcripts Volume 1 and 2. But you don't need to have that in front of you. If you do, however, I'll give you time to pull it out. 174 MR. BETTS: Thank you. You go ahead. 175 MS. PERSAD: So dealing with the first issue, then, as stated in the settlement proposal under issue 5.1, there was a complete agreement amongst the parties at the settlement conference on the company's forecast of gas, transportation and storage costs for the test year. Parties also accepted that there may be a need for additional upstream transportation capacity for fiscal 2005. The one exception upon which no settlement was reached is the cost consequences of a contract for storage services that the company entered into with Union Gas Limited dated March 31, 2004, and that contract is referred to as contract number LST039, and I'll be referring to it in my argument as simply the storage contract. 176 In addition to concerns about the fact that the negotiated prices under the storage contract exceed Union's current cost-based rates for storage, some intervenors also expressed concern about the advisability of entering into a ten-year commitment in light of the Natural Gas Policy Review, what we called in the settlement proposal at least, or what the Board refers to as the Natural Gas Forum. 177 Section 39(2) of the Ontario Energy Board Act requires Board approval of the parties to, the period of, and the subject storage of gas storage agreements. Union applied for and received the Board's approval for the storage contract pursuant to this section earlier this year as part of Board proceeding docket number RP-2004-0137/EB-2004-0126, and this was subject to Union filing the executed contract with the Board. Union's application was dated February 25th, 2004 and the Board's approval was issued on April 1st. In that decision, the Board expressed no concerns with any aspect of the storage contract. 178 In the company's view, the Board's decision to approve the contract in that proceeding answers any concerns that intervenors may have, at least about the advisability of entering into a ten-year commitment, whether in light of the Natural Gas Forum or otherwise, given that the Board approved the period of the contract in that case. 179 In this case, the company urges the Board to approve the cost consequences of the storage contract and to confirm that the Board accepts all aspects of that contract as it relates to Enbridge Gas Distribution. The company's rationale for entering into the storage contract is explained in the prefiled evidence at Exhibit A3, tab 2, schedule 5, plus attachments, of which there were two, and was summarized by Mr. Brennan in examination-in-chief at Volume 1 of the transcript, paragraphs 907 to 916. 180 In his description of the storage contract, Mr. Brennan explained that it was negotiated as a partial replacement for the company's existing storage and transportation contract, contract number M12001, or what's referred to in the evidence as the S&T contract. The evidence, that's Exhibit A3, tab 2, schedule 5, at page 2, explains that the other arrangements made as a result of those negotiations consist of two transportation contracts to replace the transportation components of the S&T contract, and those are an easterly firm transportation contract, contract number M12079, and a westerly firm transportation contract, and that one is contract number C10050. 181 Now, briefly with regard to the negotiations that culminated in the storage contract, Enbridge Gas Distribution held the view that the S&T contract would have expired on March 31, 2006 according to the terms of that contract. And that reference is at Volume 1 of the transcript, paragraphs 1274 and 1317. In Union's view, however, the S&T contract expired two years earlier on March 31, 2004. And the reference for that is Volume 1 of the transcript, several paragraphs refer to that, 1290, 1298, and 1317, as well as Undertaking J.1.5, which was Union's written notice to Enbridge Gas Distribution that the contract would be expiring. 182 In order to avoid a lengthy legal process and to attempt achievement of a mutually acceptable solution to this dispute, Enbridge Gas Distribution agreed to consider a 2004 termination of the S&T contract provided the company could demonstrate that there was a benefit to its ratepayers in doing so. And that's at the first volume of the transcript, paragraphs 1318 and 1328. And as Mr. Brennan stated also on the witness stand, "that was the only reason that [the company] Would consider it," that is to benefit the ratepayers, and that's at the first volume of the transcript, paragraphs 1318 and 1340. 183 Mr. Brennan explained that the storage contract is for the same capacity as the S&T contract, that being 21 -- approximately 21 million gigaJoules, or 19.9 Bcf, and the term of the storage contract is for ten years. The terms and conditions of the storage service under this contract are the same as those found in the S&T contract until, and this is in accordance with section 4.04 of the contract, which is filed as -- I believe it's attached B to the exhibit in the reference, A3, tab 2, schedule 5, and section 4.04 of the contract stipulates that the terms and conditions of the storage service under the contract would be the same in the old contract until the earlier of sub A, the date the company receives approval from the Board for the recovery in its rates for the charges of the storage service over the period April 1, 2004 to December 31, 2005, or such earlier date as the Board may determine; and sub B, March 31, 2006, should the Board not approve the recovery of the new storage charges by Enbridge Gas Distribution in its rates, in which case the storage contract would effectively be terminated. 184 The charges for these storage services are negotiated rates under Union's C1 rate schedule, which is the storage and cross-franchise transportation rates. 185 Mr. Brennan summarized the benefits of the storage contract in examination-in-chief as follows: 186 Firstly, he referred to the NPV analysis, that is, the net present value analysis, as outlined in attachment B to Exhibit A3, tab 2, schedule 5. This was updated as part of Undertaking J.1.3. I don't think you need to turn this up, Mr. Chairman. I'm just going to refer to one number from it, and you'll probably recall what that number is. The company estimates a net present value benefit from the storage contract and related transportation contracts over the ten-year term of $11.855 million that will accrue to ratepayers. This analysis is based upon the company's comparison of the costs of the storage contract with similar services provided in the competitive storage market, taken from responding proposals to an RFP that the company issued for such services, and that RFP is filed in response to Undertaking J.1.7 on the record. 187 The second benefit is the continued access to storage. The storage contract provides assurances to ratepayers that the company will have access to storage over this ten-year period, therefore providing some certainty to ratepayers that storage will be available. In response to a question from you, Mr. Chairman, at the second volume of the transcript, paragraphs 403 to 405, Mr. Brennan stated that the Union storage for which the company contracts represents approximately 18 percent of the company's total storage capacity. Mr. Brennan elaborated on the company's need for storage in response to questions from Direct Energy's counsel, Ms. Aitken, at volume 2 of the transcript, paragraphs 285 to 292. He stated that he could not see the company's need for storage decreasing over time. In fact, he estimated that the company may require an additional 10 to 15 Bcf of storage capacity in order to serve its growing market of heat-sensitive customers. 188 The third benefit that Mr. Brennan stated was in regards to additional deliverability. The storage contract, and this is pursuant to clause 5.01C, provides additional deliverability above the standard service, that is, an advantage of 1.4 percent deliverability compared with the standard deliverability of 1.2 percent. And this is at the first volume of the transcript, paragraph 913. 189 The fourth benefit is additional injection period flexibility; that is, under the storage contract, and this is pursuant to clause 5.01B, the company has additional flexibility on the injection period. Whereas the standard service allows for firm injections up to the end of October, the storage contract permits firm injections up to the middle of November. 190 The fifth benefit is the possible reduction of storage capacity that the company is taking under the contract over time. Mr. Brennan noted that this was an especially extraordinary benefit, in his view, for the company to be able to take under the storage contract less capacity by 20 percent in any year after 2006 with two years' notice to Union, and this is pursuant to clause 5.02 of the storage contract. This provision allows the company to take advantage of capacity that it or its affiliates develop in the future that may be less expensive than the storage services that Union is providing. Mr. Brennan noted that this benefit was not factored into the company's now $11.855 million estimated net present value, and that doing so could increase the net present value and resulting ratepayer benefits. 191 The sixth benefit that Mr. Brennan noted is the additional timing flexibility under the contract. There is no requirement in the storage contract for the company to utilize its storage capacity, that is, to empty storage, by the end of June which is normally the case for Union's standard service. 192 And finally, the storage contract is assignable, which Mr. Brennan considered to also be a benefit. And that is pursuant to clause 13.01 of the storage contract. 193 Based on these benefits, Mr. Brennan stated his firm belief that the storage contract is in the best interest of ratepayers, and this is at the first volume of the transcript, paragraph 916. 194 So for all of these reasons, Mr. Chairman, we reiterate our request that the Board grant its approval for recovery of the associated costs for the test year. That concludes my submissions on this first issue. 195 MR. BETTS: Thank you. No questions at this point, Ms. Persad. 196 MS. PERSAD: Thank you. I'll proceed, then, to the second issue that I'm going to address this morning. These are the rate design issues which actually subsume two issues, and if you would like to have the evidence in front of you, but again I don't think you need to because I won't be making complicated references to what is in there, the main piece of evidence to have before you would be Exhibit H1, tab 1, schedule 3. 197 The company undertook an extensive review of its cost allocation and rate design for the 2005 rates case, and this is at volume 6 of the transcript, paragraph 470. And as a result, the company proposed a number of changes, all of which are described in the evidence primarily at the exhibit number that I just referred you to as well as Exhibit G1, tab 1, schedule 2, dealing with cost allocation. Participants in the settlement conference achieved settlement on a large majority of these changes that the company proposed. The only two upon which complete settlement was not reached are identified as issues 15.1 and 15.2, both dealing with rate design in the settlement proposal. Parties did, however, reach a partial settlement on these issues, meaning that many parties did support the company's proposal. 198 The first of these issues is rate seasonality, and that's issue 15.1. This is the company's proposal to remove rate seasonality for all rate classes except rate 135. Currently, the company's delivery charges are seasonal in nature; that is, the company has two different sets of rates for most rate classes - one set for the winter season, which is December to March, and one set for the summer season, that is, April to December. This is explained at the sixth volume of the transcript, paragraph 444. Certain of the company's rate classes do not have seasonal rates because of the nature of the services that underpin those rates and are therefore not affected by the company's proposal. These are rate 9, the container service, rate 300, firm transportation service, and rate 305, interruptible transportation service. Rate 135, seasonal firm service, is unique in that it is designed as a seasonal service and will not change. 199 As a result of this settlement in its fiscal 2004 rates case, this is from issue 4(b) in that settlement proposal, the company agreed to conduct a review of rate seasonality for all rate classes, following its revision to the seasonal differential in rate 6. This review led the company to conclude that the benefits of eliminating rate seasonality far outweigh the perceived advantages of maintaining it, and the bill impacts are very small. As such, the company proposed this change and I urge the Board to accept it for the reasons I will outline. 200 First, to understand what costs are captured in the seasonal differential. The current seasonal differential in rates, for example, for rate 1 it is 2.5 cents per cubic metre, partially reflects the incremental cost of delivering gas in the winter months. It is a partial reflection because it only accounts for the annual cost of delivered storage, including Tecumseh and Union storage and transportation, and storage and transportation on TransCanada PipeLines. 201 The other elements of the incremental cost of delivering gas in the winter, for instance, the cost of delivered supplies, curtailment, discretionary and peaking supplies, are captured as part of the load balancing component and included in the calculation of the PGVA reference price. The reason for allocating costs in this manner is explained in the evidence in response to VECC Interrogatory No. 116. I don't think you need to turn that up, Mr. Chairman. That response simply states that the company's gas cost purchases occur over a 12-month period and rates are set using an annualized approach, even if the driver of certain costs is the need to meet winter demand. So recovering such costs on a seasonal basis separates cost incurrence from cost recovery. 202 The company believes there are several benefits to eliminating rate seasonality as described by Ms. Giridhar in examination-in-chief at Volume 6 of the transcript, paragraphs 447 to 450. These benefits are, first, a simpler rate structure and therefore less customer confusion. What most customers would now see on their customer rate notices if the company's proposal is approved is only one set of delivery charges rather than two. Customers are already faced with complex enough energy pricing, with quarterly commodity price changes and several components on already on the bill, including the customer charge, the delivery charge, the gas supply charge, and various potential riders as a result of the QRAM process. Ms. Giridhar explained that having the two sets of rates on the rate notices, one of which is irrelevant in most cases, causes a certain level of confusion for some customers which the company would like to avoid. And that's at Volume 6 of the transcript, paragraph 449. 203 The second benefit of removing seasonality that Ms. Giridhar explained is that it streamlines the QRAM presentation somewhat. Currently, the company produces two sets of rates for each of the eight rate classes that incorporate seasonality for each QRAM application, that is, at least four times a year. However, in three out of those four quarters, the company only uses one of those two sets of rates because three of these quarters fall either entirely within the summer period or entirely within the winter period. Only in the quarter beginning in October would both rates be effective, that is, the summer rates for October and November and the winter rates for December. The company's efforts to produce the additional set of rates is therefore superfluous for the three quarters other than the October quarter. 204 The third benefit of removing seasonality at this time is that it has a minimal bill impact. The removal of rate seasonality has a small impact on customers and is revenue neutral within each rate class. The precise bill impacts on a percentage basis for each rate class are listed in the evidence at Exhibit H1, tab 1, schedule 3, page 3, table 1. For some customers, there is a slight increase in their bill, and for others, a slight decrease. Ms. Giridhar gave several examples of the bill impact in examination-in-chief. For a water heater-only customer, for instance, which constitutes approximately 1 percent of the company's customer base, there will be an increase of 50 cents on the monthly bill. This is from Volume 6 of the transcript, paragraph 456. For a typical customer, however, that is, one that has a water heater and furnace using natural gas, the impact would be 7 cents per month. That's volume 6 of the transcript, paragraph 457. 205 And the fourth and final benefit that Ms. Giridhar outlined is that removing rate seasonality would bring the company into alignment with other Canadian gas utilities. Currently, Enbridge Gas Distribution is the only Canadian gas utility that has rate seasonality, according to a survey that the company conducted recently. And this is explained at Volume 6 of the transcript, paragraph 450. If rate seasonality were a powerful incentive for consumers to practice energy conservation, or if it provided any other significant benefits, one would expect other gas utilities to adopt it. Because this has not occurred, the Board should question the need for the company to maintain it. 206 In determining this issue, though, the Board must weigh the noted benefits of eliminating rate seasonality against any advantages of maintaining it. As the evidence states, the only perceived shortcoming of non-seasonal rates is that they would dissuade conservation efforts. The company tested this proposition by examining the impact of removing seasonality on the payback period of high-efficiency furnaces relative to mid-efficiency furnaces. The company found that the normal two-year payback period increased by less than one month for the typical rate 1 customer, assuming no rate seasonality. And this is explained at Exhibit I, tab 18, schedule 115. It's VECC Interrogatory 115. The company therefore concluded that eliminating rate seasonality would not have a material impact on conservation efforts. 207 This conclusion is strengthened by Ms. Giridhar's explanation of the relative impact of the seasonal differential on consumer behaviour compared with the commodity or gas supply price. She stated that the company's seasonal rates stem from an era of fixed long-term commodity prices. In the early 1990s, the commodity price was approximately 6 to 8 cents per cubic metres at certain times compared with a seasonal differential of 2 cents per cubic metre in 1991. Today, the seasonal differential for rate 1 is 2.5 cents per cubic metre and the commodity charge in the company's most recent QRAM application is 28 cents per cubic metre. And this is explained at volume 6 of the transcript, paragraph 453. Therefore, the seasonal differential was approximately 33 percent of the commodity charge in the early '90s and is only about 9 percent of it today. 208 Ms. Giridhar also noted in her prefiled evidence that the company is able to capture gas supply price volatility through the quarterly rate changes prescribed by the QRAM. This is in evidence Exhibit H1, tab 1, schedule 3, page 2. And this is an important development given that the commodity price is clearly the more material of the two price signals. In the company's view, consumers are far more influenced by the commodity price than by the seasonal rate differential in the delivery charge. Ms. Giridhar quantified her opinion with her illustration of a typical rate 1 customer who would consume only one-quarter of a cubic metre of gas more before the 28-cent commodity price would cause an increase in their bill. She gave this example at volume 6 of the transcript, paragraph 457. 209 For all of these reasons, the company submits that the seasonal rate differential is an immaterial consideration to energy conservation behaviour, and in light of the benefits of removing it, the Board ought to approve the company's proposal. 210 I'll now move on to the second of the rate design issues and this is the increase to the rate 1 customer charge, issue 15.2. 211 The company's proposal is to increase the monthly customer charge for rate 1 from $10 to $11.25. The existing $10 customer charge for rate 1 has been in place since the 2000 test year. That's explained at volume 6 of the transcript, paragraph 471, and in response to VECC Interrogatory 117, page 2. That's almost five years ago since this customer charge has been reviewed by the company. 212 The monthly customer charge is designed to recover fixed costs related to serving the customer class. These are the customer-related costs, such as general plant, that is, meters and pipe, meter-reading costs and customer-related operations and maintenance costs, such as call centre, billing, and credit and collections. This is explained at volume 6 of the transcript, paragraph 472, by Ms. Collier. At the $10 level, the monthly customer charge for rate 1 recovers approximately 50 percent of these customer-related costs. Because the rate 1 class is very homogeneous in the degree to which each customer incurs these fixed costs, the 50 percent recovery tends to result in intraclass cross-subsidy that a higher percentage of recovery through the customer charge reduces. Therefore, it is desirable from a pure rate design perspective that a higher proportion of the fixed costs be recovered through a fixed charge in order to better match cost incurrence with cost recovery. Ms. Giridhar -- Ms. Collier explains this, rather, at volume 6 of the transcript, paragraph 473, and in the evidence at page 4. 213 At the increased level of $11.25, the customer charge reflects a cost recovery of approximately 60 percent of the related fixed costs of that rate class. The company views this level of increase as modest, and likely acceptable to customers at this time, especially in light of the relatively modest increase in other portions of the gas bill that customers may be incurring with this rate application. This is explained at volume 6 of the transcript, paragraphs 587 and 588. Further, this level of recovery is consistent with the level of cost recovery that Union Gas has instituted by recently increasing its equivalent-to-rate 1 customer charge pursuant to Board approval from $10 to $12 for 2004, and eventually to $14 for 2005. The docket number for this case is RP-2003-0063. The Board's decision is found at pages 145 to 146. Ms. Giridhar also noted that Toronto Hydro has a $14 customer charge. This is explained at volume 6 of the transcript, paragraph 589. 214 So like the company's proposal to eliminate rate seasonality, the proposed increase in the rate 1 customer charge is revenue neutral. Ms. Collier explained that this is why in terms of bill impacts, the larger volume rate 1 customers will actually see a slight decrease in their monthly bill, while a small-volume rate 1 customer would see a slight increase. In most instances, these impacts are negligible. Ms. Collier illustrated this point with the following three examples. This is found at volume 6 of the transcript, paragraphs 476 to 480. 215 The first example is a larger volume rate 1 sales service customer who consumes approximately 5,000 cubic metres of gas per year, who would experience a decrease of 0.5 percent, or approximately $9.80 per year on their bill. This equates to an 82-cent decrease per monthly bill. 216 The second example is a typical residential rate 1 customer who consumes about 3,000 cubic metres of gas per year on sales service, their annual bill would decrease by about 74 cents per year, or 6 cents per month. 217 And finally, for a smaller volume rate 1 sales service customer, again this constitutes only about 1 percent of the company's customer base, who consumes approximately 1,000 cubic metres of gas per year, they would see an increase of $9.48 per year on their bill, or about 79 cents per month. 218 These bill impacts are particularized in table 2 on page 4 of Exhibit H1, tab 1, schedule 3, on a percentage basis and in response to Energy Probe Interrogatory No. 88, part C, in dollars. 219 So that concludes my submissions, Mr. Chairman, on the rate design issues, subject to any questions the Board may have. 220 MR. BETTS: Ms. Persad, the Board Panel has no questions, thank you. Please proceed. 221 MS. PERSAD: So the final issue I'm going to address this morning is with regard to the company's proposal to establish, for test year 2005, a class action suit deferral account, or CASDA, to record costs incurred in defending late payment penalty litigation, or the Garland case, including any judgment against the company, and this is issue 11.2. 222 The company's proposal in this regard is set out in the prefiled evidence at Exhibit A8, tab 1, schedule 1. And I don't believe you need to turn it up again. 223 The settlement proposal also outlines the following with respect to this issue: 224 As a result of the Supreme Court of Canada's decision of April 22nd, 2004, the company is required to now repay late payment penalties collected from the plaintiff in the Garland case in excess of the interest limit stipulated in section 347 of the Criminal Code after the Garland case was commenced in 1994 in an amount to be determined by the trial judge. 225 Parties to the settlement proposal acknowledged that the Supreme Court's decision in the Garland case has implications beyond the company and will likely require repayment of late payment penalties in contravention of the Criminal Code by numerous other gas and electric utilities in Ontario. Because of this, parties agreed that the issue of whether such payments are properly recoverable in rates is a matter appropriate to be considered by the Board in a funded generic process in which all stakeholders can participate. 226 However, in the absence of direction from this Board Panel in respect of this process, the parties agreed that the issue in this case is, should the Board establish the 2005 CASDA, and if so, what costs should be recorded therein? 227 Before the company's witness panel was introduced on this issue, the Board Panel did make a statement that helped to further focus this issue, and that can be found at Volume 5 of the transcripts, paragraphs 925 to 929; that is, the Board Panel stated that it could not confirm that the larger Board would undertake a generic proceeding dealing with utility late payment penalties. Furthermore, the Board delineated its consideration of the issue as determining whether to approve establishment of the requested deferral account without determining whether any of the amounts to be recorded in the account would eventually be recovered from ratepayers. The Board Panel asked parties to restrict their treatment of this matter to this narrow framing of the issue, that is, to the type of costs to be included in the account rather than the forecast amounts. 228 While the company certainly acknowledges and appreciates the limitations of this issue as framed by the Board Panel, the company does wish to express its view, however, that a generic proceeding would be most appropriate to deal with the cost recovery aspects of the late payment penalty issue given its broad implications for gas and electric utilities. This is especially so in light of the fact that a similar action was commenced against all Ontario municipal electric utilities in 1998, and Union Gas Limited was recently served with two statements of claim, one on May 14 of this year and one on June 3rd of this year, from plaintiffs claiming relief similar to Mr. Garland. Further, 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 the matter. Union's application was filed with the Board -- for this deferral account, that is, was filed with the Board on June 22 of this year, docket number RP-2003-0063/EB-2004-0386. 229 However, whether or not the Board decides to convene a generic process to resolve the late payment penalty cost recovery issue, the company believes that there is a compelling need for establishment of the proposed 2005 CASDA to record or track both the costs of defending the Garland litigation and the costs of any related judgment at this time. 230 I'll just briefly now refer to the history of that account and the late payment penalty. 231 The company's response to Energy Probe Interrogatory No. 117, and again, I don't believe you need to turn it up, provides copies of all filings and regulatory decisions related to the 2005 CASDA and its predecessors and a concise history of the account and late payment penalty charge. The company's witnesses summarized this history in examination-in-chief at Volume 5 of the transcript, paragraphs 967 to 982, noting that the Board first approved an account to record costs associated with the Garland litigation when it was commenced in 1994. As can be seen from that exhibit, the response to Energy Probe Interrogatory No. 117, the description of the deferral account did vary somewhat over time in accordance with the status of the litigation. The Board has approved disposition of the account since its 1994 inception with some variance in timing of disposition in certain years. 232 As the Board is not determining whether the costs to be recorded in the 2005 CASDA are recoverable at this time, I don't propose to give a summary of the company's application of the late payment penalty or its rate treatment in this presentation. Rather, I will focus my submissions on what the Board must consider in determining whether the 2005 CASDA is the most appropriate accounting treatment for the costs that the company is seeking to track in that account. 233 So we come to the crux of the issue, and first I'll deal with the regulatory treatment of deferral accounts. 234 In examination-in-chief, Mr. Ladanyi drew upon his 13 years of experience in providing an overview of the traditional regulatory treatment of deferral and variance accounts in the context of the forward test year rate-making process, and he explained this at Volume 5 of the transcript, paragraphs 984 to 992. He explained that the Board has allowed the creation of these accounts in order to deal with certain circumstances and significant inequities that can result -- that can arise, rather, as a result of the forecasting process. In general, deferral accounts were created to deal with costs or revenues that are anticipated to be incurred in the test year and are inherently unpredictable. This method of accounting for costs or revenues in a fiscal year allows the Board to deal with such amounts in a later year when their magnitude is known. Mr. Ladanyi referred to the Board's Uniform System of Accounts description of deferral accounts in support of his explanation, and I'll just refer to that description briefly. 235 "This account shall include expenditures that cannot be disposed of until further information is received." That's a direct quote from the Uniform System of Accounts and it's also in the transcript. "Expenditures of a delivered nature not provided for elsewhere are to be amortised over a future period." That's the end of the quote. 236 In response to questions from IGUA's counsel, Mr. Thompson, at Volume 5 of the transcript, paragraphs 1050 to 1065, Mr. Ladanyi further explained that a deferral account is either an account receivable or an account payable, neither of which are part of rate base. Unlike a notional account, the deferral account would have actual accounting entries to be disposed of by the Board at some future time. Mr. Ladanyi stressed that deferral accounts do not imply any Board ruling on future disposition. 237 So the Board typically considers certain criteria when determining whether to approve establishment of deferral accounts in any particular case, and I'll refer here to a June 18, 2004 decision issued by the Board, docket number RP-2000-0005/EB-2004-0249, which granted an application by Union Gas to establish a deferral account to capture the incremental amounts to be paid to storage landowners in accordance with the Board's decision in that case. And the establishment of that deferral account allows Union to record the difference between the payments made to compensate certain landowners in respect of the right to store gas and the compensation for storage rights included in rates as approved by the Board. And I give this only for the purposes of background for this decision. But the important thing to focus here on is what criteria the Board considered in granting that application. And these are, number 1, the nature and magnitude of the expense to be recorded in the proposed deferral account; secondly, the timing of the expenses and whether they were anticipated; and thirdly, whether the amounts are eligible for the Board's future consideration and disposition. 238 I submit that the Board's summary of the deferral account criteria in the Union case is aligned with Mr. Ladanyi's overview and serves as the framework upon which the company has organized its further submissions that explains why the Board ought to grant the company's request at this time. The company's proposal to establish the 2005 CASDA satisfy these Board criteria, as I will outline. 239 The first criteria, again, is the nature and magnitude of the expense to be recorded in the proposed deferral account. If the Board accepts that a 2005 class action suit deferral account should be established, then it must determine what the parameters of that account should be; that is, it must determine whether the nature of the expenses proposed for recording are appropriate. 240 The nature of the expenses originally proposed by the company to be recorded in the deferral account are, as described by Mr. McGill, threefold, and these are described at volume 5 of the transcript, paragraphs 963 to 966. 241 First, the legal costs of both the company and the plaintiff; secondly, because the company's defence of the Garland case will require assistance and expert advice from actuaries and a considerable effort to gather and analyze the extensive and detailed historic billing records in order to establish the amounts that may be subject to the litigation, the company proposes to record the costs of this work in the account; and finally, the company seeks to record the amount of any judgment against it, including any award by the court regarding the plaintiff's costs. 242 Now, a fourth component that was explored with the witness panel in cross-examination is what was referred to as amounts related to mitigation efforts the company has undertaken to reduce these costs, and this was explored at transcript volume 5, paragraph 1306; that is, costs recoverable from some other party, such as an insurer, that would be available to offset a judgment against the company. Any amount in this category would operate as a credit to the 2005 CASDA, reducing any amount the company would propose to recover from ratepayers in future years. The witness panel accepted this component as a fair addition to what the deferral account should reflect. And this is at volume 5 of the transcript, paragraph 1318. 243 Now, while we don't know other parties' positions on this issue yet, Board Counsel did explore the possibility in cross-examination, at volume 5 of the transcript, paragraph 1408, that intervenors could argue that certain of the proposed components of the deferral account be included, such as Enbridge's own litigation costs, and certain components be excluded, such as the costs of the judgment and the legal costs of the plaintiff. 244 As Mr. Ladanyi explained on the stand in response to that question, the company would certainly prefer to have some account rather than no account at all. And this is at volume 5 of the transcript, paragraph 1411. However, Mr. Ladanyi also noted that the purpose of the deferral account is to keep track of all of the proposed costs as they are incurred throughout the year rather than expensing one or more of them. Volume 5 of the transcript, paragraph 1458. 245 And I have two further comments to make about a potential segregation of the costs to be captured in the deferral account. 246 The first is this: The company will likely be incurring these costs throughout the test year, depending upon the specific nature of the expenses. The costs of actuaries and other third-party labour required to analyze billing records and to establish the amounts that may be subject to the litigation will likely be incurred over an extended period of time rather than as a lump sum. The plaintiff's legal costs, however, and the costs of any judgment that may be incurred will be incurred as a lump sum, most likely, in accordance with the judgment of the trial court or an assessment officer as it relates to the issue of costs, or may be subject to some kind of recovery or repayment management as determined by the court. And you raised this possibility with the witness panel, Mr. Chairman, with Mr. Boyce in particular in questioning him at volume 5 of the transcript, paragraphs 1450 to 1453, to which Mr. Boyce responded that it is certainly possible that the court would provide direction as to how the repayment would be managed, and that it could direct that the Board would somehow be involved in that process in some sense. But we just simply can't predict. 247 The second comment I have to make about potentially segregating the costs in the deferral account is that there is no evidence before the Board in this case that would enable it to make a clear delineation between what ought to be included and what ought to be excluded of the costs proposed. All of the costs the company is proposing to be recorded in the 2005 CASDA are similar in nature, that is, they stem from the company's defence of the Garland action. Also of significance is the fact that the Garland litigation has continued now for more than a decade, and the Board has approved the recovery and disposition of all the costs incurred by Enbridge Gas Distribution in defending this matter since its commencement. Therefore, these are not expenses that are unfamiliar to parties or to the Board. The only difference for the 2005 test year is that the status of the litigation is such that the company has now been ordered by the Supreme Court to repay the late payment penalties collected from the plaintiff in excess of the interest limit stipulated in the Criminal Code. 248 This decision of the Supreme Court necessarily extends the cost components associated with the Garland case, but it does not change the essence of the company's request to again establish a deferral account for the 2005 test year to record such costs. In the company's view, it would be an artificial distinction for the Board to determine that some of the costs related to the Garland case should be recorded in the account and others should not. The history of the Board's acceptance of this account, therefore, in the company's view, supports the company's proposal within the parameters outlined, that is, the Board's cost component, including the net-of-mitigation-efforts qualifier. And on a more practical note, it would be more efficient to track all of the costs associated with the Garland case together in the same account rather than to segregate them into different components and potentially cause an inconsistent treatment of them in terms of timing and/or policy. 249 The company submits that the magnitude of the expenses is also a relevant consideration for this Board, at least in a general sense, even though the Board is not embarking upon an examination of the magnitude per se in this hearing; that is, the Board should take into account the fact that the potential costs to the company are significant and the range is large. And this is explained at Volume 5 of the transcript, paragraph 998. Therefore, any adverse effect on the company and its shareholder of having to expense costs stemming from a 2005 court judgment against its 2005 fiscal earnings is equally significant. This is explained in the transcript at Volume 5, paragraph 994. 250 So the Board should weigh this adverse effect against the effect of the Board's other alternative of granting the proposed deferral account. The company submits that ratepayers would not be similarly prejudiced in the event that the Board permits establishment of the account as proposed, because the question of whether the recorded amounts are recoverable is still determinable, and, according to section 36(4.2) of the Ontario Energy Board Act, the Board will make that determination within 12 months of the account's establishment thereby ensuring a timely disposition of the account. 251 I now come to the second of the Board's criterion from the Union Gas case, and that is the timing of the expenses and whether they were anticipated. 252 The timing of the expenses that the company seeks to record in the 2005 CASDA are potentially imminent as they relate to the 2005 test year. And this is explained in Volume 5 of the transcript, paragraph 998 and paragraphs 1353 to 1356. The history of the CASDA and its various predecessor accounts has mirrored the status of the Garland litigation at any given point in time. The more imminent the cost incurrence, the more urgent the need for the appropriate accounting mechanism. Like it has for the 2005 test year, the company proposed to include the language "including any judgment against the company" in the 2004 class action suit deferral account in anticipation of receiving the Supreme Court's judgment in 2004. Having received that judgment, the company now has to deal with the consequences of the court's order to repay late payment penalties subject to determination of the amounts and the class of persons to which those amounts are payable. As noted, the company anticipates that costs related to the court's judgment will very likely be incurred in the test year, but we are uncertain about the precise timing of the cost incurrence. In any event, I do submit that the imminent threat that the costs will be incurred in the test year satisfies this second criterion of the Board's, that is, the timing of the expenses. 253 The third of the Board's criteria is whether the amounts are eligible for the Board's future consideration and disposition. 254 The Board's opening statement about limiting discussion of this issue to whether the 2005 CASDA should be established, and to not discuss matters concerning whether the proposed costs are recoverable, precluded examination of the eligibility of the amounts for future disposition in this case. The Board's desire to focus the issue in this case is understandable in light of the many outstanding factors yet to be determined in the Garland litigation. The Board itself recognizes this in its fact sheet on utility late payment penalties, which was filed at Exhibit K.5.4 in this hearing, and it explains that: 255 "The Board continues to study policies and practices regarding the charging of late payment penalties by both natural gas and electricity utilities. This includes topics such as: What interest rates are appropriate, for what period they should be charged and what provisions are made for customers who make reasonable efforts to pay bills on time but may pay them after the due date." 256 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. On the other hand, the fact that the Board has permitted disposition of amounts incurred in defending the Garland litigation for the past ten years supports the assumption that there is at least a possibility that the Board will allow the company's claim, or may allow the company's claim for recovery of the costs in the account. This possibility, I submit, no matter how remote it may be, should serve to satisfy the eligibility criterion in favour of the establishment of the account. 257 So for all of these reasons, Mr. Chairman, the company submits that its proposal to establish the 2005 CASDA is consistent with the Board's criteria for approving deferral accounts. 258 And the last point about this issue I do want to address is the accounting order alternative. 259 The witness panel was asked to comment on whether the company could apply for an accounting order at some later date in order to establish the subject account or to expand its application were the Board to conclude that the company's proposal is premature at this time. Mr. Ladanyi responded that in his experience, the Board's normal practice or preference is to deal with such matters in a rate case rather than outside of a rate case. And this was at Volume 5 of the transcript, paragraphs 1455 to 1458. That is, accounting order applications tend to be more routine and expedited in nature and do not normally receive the same extensive scrutiny by interested parties as issues raised in the context of a rate case. Also, Mr. Ladanyi noted that the purpose for having the account is to not lose track of any of the costs related to the Garland litigation or to be expensing these costs during the year. And this is easier done if we deal with all of the costs together. 260 The company further submits that if the Board were to deny the company's request in this case as premature, the company would still be uncertain about when the Board would consider such a request to be timely. As noted previously, the nature of the expenses to be recorded in the 2005 CASDA are both ongoing and more finite in nature. However, until we have the court's decision in that regard, we really don't know. Coupled with the fact that the types of expenses recorded therein are not clearly distinguishable from each other, we suggest it would be more efficient and logical to treat all of the expenses similarly and to allow their tracking as a group rather than piecemeal. 261 Finally, if the Board is considering convening a generic process or hearing or other process to consider the repayment and recovery issues also now faced by other gas and electric utilities, granting the company's request at this time to record all related costs in the 2005 CASDA is, in the company's view, the most efficient and appropriate accounting mechanism for dealing with the costs at this time. Then, in the generic proceeding, the Board could deal with all of the repayment and recovery issues at once without the concern that certain of the subject costs may have already been expensed and borne by utility shareholders. 262 Although the company would certainly avail itself of the option to apply for an accounting order in the event the Board were to deny its request in this case, for the foregoing reasons, the company does not view the accounting order as a very practical alternative in these circumstances. 263 That concludes my submissions, Mr. Chairman, subject to any questions. 264 MR. BETTS: The Panel will confer for a moment. 265 [The Board confers] 266 MR. BETTS: Thank you. The Board Panel has no questions, Ms. Persad. And am I correct that that concludes your arguments on those three sections? 267 MS. PERSAD: Yes, it does, Mr. Chairman. I believe Mr. O'Leary would follow me. 268 MR. BETTS: And Mr. O'Leary, I'm wondering whether, again, this might be an appropriate time to take a break and come back with your arguments. 269 MR. O'LEARY: I'm in your hands, sir. I do believe that I would -- I was going to start with risk management and I do believe that I would have that argument completed before 1:00. 270 MR. BETTS: I think, then, having heard that, let's proceed with that portion and we'll break following that. 271 MR. O'LEARY: Thank you, sir. 272 MR. BETTS: Please proceed. 273 SUBMISSIONS BY MR. O'LEARY: 274 MR. O'LEARY: If I may commence my submissions in respect of the risk-management issue with respect to preliminary comments, the first relates to nature of the issue as it's framed itself, and that is that it is a review of the report by RiskAdvisory which reviewed and made recommendations with respect to the company's risk-management program and then the company's response to that report. And I highlight that because the issue before the Board in this proceeding is, therefore, limited to the conclusions and recommendations made by RiskAdvisory and the company's response to it. An issue which is not live before this Board is whether or not risk-management activities should continue. 275 Just to remind you, the RiskAdvisory report is found at Exhibit A3, tab 3, schedule 1, and the company's response is found at Exhibit A3, tab 3, schedule 2 of the prefiled evidence. The history of it is somewhat relevant in that the RiskAdvisory report is the genesis of an agreement that was reached by all parties in the fiscal 2003 rate case, RP-2002-0133. 276 One must presume, and again I remind the Panel that it was all parties that agreed to this, that all parties understood that there would be costs incurred with respect to the RiskAdvisory report, and that they expected that there would be recommendations made by RiskAdvisory and that ultimately, if the recommendations were sound, that they would be acted upon. 277 I trust it's also not presumptuous for me to suggest that the Board Panel had approved that settlement proposal, similarly understood that there would be costs incurred, and that there would be likely recommendations made, and that if they were sound, they would be acted upon, and that retaining RiskAdvisory and receiving a report from them would not amount to solely an academic exercise. 278 I suggest, if I may turn first to what it is that the company is looking for in terms of an approval from the Board, the company proposes to implement as soon as practical after receiving approval from the Board a number of the changes recommended by RiskAdvisory. These changes are specifically identified in the prefiled evidence as table 1, and that was referred to in the company's response at A3, tab 3, schedule 2. And that table was the reference that was referred to on many occasions during cross-examination. The company is not seeking approval at this time for the recommended changes identified in table 2 of the company's response, but it does propose to bring these recommendations forward for the Board's consideration in its application for approval for rates in fiscal 2006. 279 As noted by the company's witnesses during the oral portion of the hearing, the company is of the view that in support of the proposed changes to be implemented on or before fiscal 2005, it should undertake a customer survey to update the $35 price volatility tolerance level which was identified in the surveys undertaken in 1994 and 1995. The company's evidence on this was that the cost of the survey would likely be in the range of $80,000. 280 In support of the implementation of the changes for which approval is sought in this proceeding, the company has drafted proposed amendments to its Risk Management Policies Procedures Manual, which is found at Exhibit A3, tab 3, schedule 2, appendix 1, and the service level agreement with EGS, which is found at A3, tab 4, schedule 1. As noted by Mr. Pleckaitis, the company officer responsible for gas supply function which includes the risk-management program, at volume 2 of the transcripts, paragraph 515, the company will continue to operate its current risk-management program as currently approved until it receives a decision from the Board in this proceeding as to how it may proceed in the future. 281 Before turning to some of RiskAdvisory's recommendations in greater detail, perhaps I may highlight the conclusions which RiskAdvisory reached in respect of the company's existing risk-management program. And these conclusions are found in the RiskAdvisory report which was filed in the prefiled evidence. You will also recall that one of the witnesses that appeared with the panel in respect of the risk-management issue was Mr. Simard, who, as a result of his unparalleled expertise and experience dealing with risk-management issues, was qualified by this Panel as an expert witness and therefore authorized to give opinion evidence. 282 The conclusions of RiskAdvisory are summarized on pages 5 through 7 of the report and I wish only to highlight several portions of it. And if I may quote from page 5, RiskAdvisory stated: 283 "Overall, RiskAdvisory believes that the program objectives are generally sound. Best industry practices have been put in place and are being observed. The program has been implemented consistently and in the manner described to and accepted by the OEB and intervenor groups. The interests of the ratepayers are clearly the focus of the program design." 284 Then at page 7 they added: 285 "In summary, it is RiskAdvisory's opinion that EGD's approach to the management of ratepayer exposure to volatile energy prices has significant commonality with other North American utility risk-management programs that have received regulatory approval." 286 I should stop at that point and highlight the fact that there is, indeed, no expert evidence on the record which challenges these conclusions reached by RiskAdvisory and, as a lawyer, therefore suggest that there is no evidentiary basis for a finding by this Panel to the contrary. 287 RiskAdvisory did go on to indicate that there are areas where some improvements could be made to program design. At page 7 of its report, RiskAdvisory had the following to say, despite the conclusions which I just earlier quoted specifically, RiskAdvisory said: 288 "Several changes should be considered to improve the overall program performance and improve the company's ability to meet program objectives." 289 Now, you'll recall that the preponderance of cross-examination during the hearing related to the timing of the implementation of the recommendations made by RiskAdvisory for improvements to the program. It's the company's submission, based on review of the cross-examination, that there was very little cross-examination which attempted to draw into question the advisability of the recommendations that RiskAdvisory made. Simply put, it is the company's submission as well that there is, therefore, no evidentiary record to challenge the recommendations made by RiskAdvisory. 290 Turning to some of those recommendations specifically, the company witnesses and Mr. Simard highlighted several of the more significant proposed changes in their oral evidence. The first which I wish to highlight is the removal of the 10 percent restriction on hedgeable volumes. It is, first, important to point out that the elimination of this restriction does not restrict the quantum of hedgeable volumes but rather only the pace at which the full amount of hedgeable volumes indicated by the model can be hedged. In effect, the elimination of this 10 percent restriction will simply reduce the time frame over which the same volumes could be hedged today pursuant to existing procedures. The justification for the removal of this restriction was given by Mr. Simard at Volume 2, paragraph 531, where he stated that there is a much greater likelihood that Enbridge will be able to defend ratepayers against an increase in gas costs in excess of the tolerance amount. He then added at paragraph 532 that: 291 Given "the volatility conditions that Mr. Pleckaitis alluded to and that forward markets agree with, there is no question that market participants continue to believe that we are going to experience high levels of gas volatility for the foreseeable future." 292 "In that type of environment, I think it exacerbates the need to incorporate enhancements into the program that will serve to improve the efficiency of the program with respect to muting some of the gas-price volatility for ratepayers" 293 RiskAdvisory noted at page 27 of its report the particular limitation which the proposal to remove the 10 percent restriction is intended to address. In the middle of that paragraph, the report reads: 294 "Delays can occur with respect to the effect of implementation of hedge positions. Additional hedges cannot be executed until the existing 10 percent tranche is hedged. If hedges are not executed until the latter part of the hedge window, there will be delays in establishing further hedges at times when the model continues to show that EGD is in a hedgeable position. These latter two points exacerbate the conservatism." 295 In respect of this latter observation, and that's in respect of the conservatism, expert witness stated at paragraph 728 that: 296 "Relative to the standards RiskAdvisory has seen amongst other gas utilities" and you'll recall that Mr. Simard indicated the extent of his and his firm's experience, given that experience, their observation was that the other gas utilities who manage ratepayer exposure, the existing 10 percent limitation on hedgeable volumes which the company presently has is conservative relative to those other gas utilities. It's not something RiskAdvisory has seen elsewhere. The report then went on to state at page 27 that in RiskAdvisory's view, the guidelines around hedgeable volumes represent the largest potential impediment to the program's ability to achieve the primary risk management objective of limiting gas supply volatility. 297 Another recommendation is identified at item 8 of table 1. In his evidence in chief at paragraph 25, Mr. Simard stated that: 298 "The way that hedgeable volumes are currently calculated oftentimes results in an estimate of hedgeable volumes that lies below the company's estimate of minimum monthly system load requirements." 299 Mr. Simard continued by stating that: 300 "By moving to a determination that more closely reflects the minimum monthly volumes, the company will move more in line with other utility practices in this area. The change proposed by the company in respect of the determination of hedgeable volumes is found at page 14 of its amended policies and procedures manual." 301 You'll recall that there is a draft of the amended policy and procedures manual in prefiled evidence: 302 "Here the company has proposed the deletion of the 10 percent limitation and additional wording which allows it to hedge such volumes as is required to maintain the gas supply commodity portfolio within the tolerance band." 303 This wording, which I would have quoted in writing, is the wording RiskAdvisory has recommended relating to the determination of hedgeable volumes. 304 A further proposed change identified at table 1 of the company's response to the RiskAdvisory report at item 12 would allow the company to hedge volumes on a rolling 12-month basis. The company submits that this change will help it reduce price volatility by, when necessary, allowing the company to continually hedge and by beginning to hedge volumes earlier than is currently the case. Mr. Brennan confirmed at Volume 2, paragraph 805 of the transcripts, that the present situation sets a limit of one fiscal year. As the year progresses, the limit restricts the company from hedging beyond the fiscal year such that as the fiscal year draws to a close, the company can only hedge during the remaining portion of the fiscal year. 305 For example, in May of a particular year, the company can only hedge until the end of September, even though opportunities to risk-manage the volatility for the coming winter months may in fact exist or present themselves. 306 With the proposed change, the company would be able to look forward for a full 12 months at any point in time during the fiscal year. By contrast, under present procedures, the company is limited from looking beyond the end of the fiscal year, as I said. If this change is approved, the company will propose specific operational changes as part of a subsequent QRAM application. Now, the operation question which exists really boils down to this, and that is how the rolling 12 months will interact with the QRAM process. As noted by Mr. Brennan at Volume 2, paragraph 802 of the transcripts: 307 "The company is considering proposing that every three months, when it proceeds with a QRAM application, it will look out 12 months from that point in time, in effect, thereby creating a quarterly rolling 12 months." 308 A further change recommended by RiskAdvisory involves the narrowing of the execution window for the AECO transactions to two days and three days for Chicago transactions. Under the present procedures manual, there is a ten-day implementation period. The justification for this change was given by Mr. Simard at Volume 2, paragraph 632 of the transcripts, where he stated that he thought historically, and I'm quoting him here: 309 "The ten-day window was there primarily as a result of the fact that liquidity conditions in the marketplace may have been such that the prompt execution of positions might not have been possible in an effective manner. Over the years, the liquidity in the forward markets improved to the point where the ten-day window was no longer required." 310 Mr. Simard added that in the current environment, with a ten-day window, someone with execution responsibility might try to judge when was the best date to execute in that window based on price view? It was the opinion of RiskAdvisory and Mr. Simard that the exercise of that price view was not appropriate and that, with today's improved liquidity conditions, the policy should be adjusted to reflect a shorter execution window. 311 The next recommendation of RiskAdvisory I wish to address relates to the proposed amendments to the wording of the objective of the program, which is found at page 4 of the amended policies and procedures manual in the prefiled evidence. The reason why RiskAdvisory proposed changes to the wording of the objectives of the program are set out at pages 11 and 12 of its report. There are essentially two elements to the proposed changes. 312 First, RiskAdvisory recommended removal of wording which suggested that the floating price is a means to participate in falling prices. RiskAdvisory pointed out that while the floating price component allows customers to participate in declines in the marketplace, it should be recognized that it exposes customers to both higher and lower prices, but that over the longer term it is likely that there will be no reduction to customers rates through the floating rate component of the portfolio. RiskAdvisory correctly pointed out that the intent of the market-based price portion of the objective is not to lower costs but rather to provide ratepayers with price transparency. Thus, RiskAdvisory recommended removal of the suggestion in the wording that the floating price is a means to participate in falling prices. 313 The second change proposed in respect of the wording arises out of the RiskAdvisory report and it relates to the latter part of the objective and specifically the wording "avoiding unacceptable price increases." In RiskAdvisory's view, at page 11 of its report, this wording overstates the capabilities of the program. Given the company's definition of hedgeable volumes, RiskAdvisory is of the view that there will always be a significant component of actual gas supply that will remain unhedged. In a high-priced environment, customers will be exposed to prices that could be beyond their risk tolerances and outside the capabilities of the risk-management program to constrain. Accordingly, RiskAdvisory recommended, and the company proposes to so change the wording at page 4 of the Policies and Procedures Manual by excluding this language which I identified just a few moments ago. 314 Now, it is important that we highlight that the proposed changes to the objectives of the program do not mean a change in practice by the company. Muting price volatility has been and remains the objective of the risk-management program. As noted by Mr. Brennan at Volume 2, paragraph 592 of the transcripts, it has never been part of the company's policy to try and get the best price. Mr. Simard of RiskAdvisory went further at paragraph 568 of the transcripts. He added that he does not believe that it is appropriate to expect utilities to use risk-management programs to achieve a better price. Mr. Simard added inherently, that would suggest that utilities have the capability to use risk-management instruments to beat the market, and that is a very, very difficult skill, a very rare skill, and a skill that RiskAdvisory does not think utilities should be expected to have. 315 Mr. Simard went on to add in response to a question asked during cross-examination about those programs in the United States that incent utilities to beat the market, that despite the incentives, in his view over the long run, he does not believe that these utilities will, in fact, be able to beat the market. At volume 2, paragraph 571, Mr. Simard stated that whenever you inject a beat-the-market mentality for the benefit of the shareholder, you increase the likelihood of potential wrongdoings and operational difficulties. 316 Mr. Simard reminded parties at paragraph 573 that a lot of independent firms earn income on a relatively risk-free basis through a network of contacts in the industry where they are able to buy from counterparties at one price and almost simultaneously sell to another and extract the margin. 317 By contrast, Mr. Simard noted at volume 2, paragraph 574, noted that those companies who rely on risk-taking positions have earnings which fluctuate dramatically and must therefore have a high tolerance for risk in order to stay in business over the long run. 318 The final proposal I intend to address of the recommendations by RiskAdvisory relate to the company's proposal to undertake a survey to update the $35 tolerance level established in 1994 and 1995. As noted by Mr. Pleckaitis at volume 2, paragraph 1122, the information the company will glean from customers in terms of their tolerance is the same as that learned by the company as a result of its earlier surveys, albeit the methodology may differ given new information that is available about what other utilities have done to obtain similar information. 319 As I indicated earlier, the estimate the cost of this survey is $80,000 and the company proposes to recover these costs through the PGVA, consistent with what is -- with the company's practice of charging gains and losses associated with the gas-supply risk-management program to the PGVA. This was noted in the company's response to Undertaking J.2.5. 320 It is the company's evidence that aside from the one-time charge for the customer survey, there are no incremental costs associated with the proposed changes in table 1. It was the evidence of Mr. Pleckaitis at volume 2, paragraph 517, that there are no incremental risks from the customers' perspective associated with the implementation of the proposed changes. Adversely, Mr. Pleckaitis, RiskAdvisory and Mr. Simard, in their oral evidence, stated that the changes will result in substantial benefits to customers through reduced price volatility. The practical effect that the Board and intervenors can expect for the implementation of these changes is an even more successful risk-management program in the future. 321 The Panel may recall from the company's response to Board Staff Interrogatory 18, found at Exhibit I, tab 1, schedule 18, that the risk-management program to date has resulted in an overall reduction of volatility of an average of 68 percent in respect of those volumes hedged during fiscal years 2001 through 2003. Upon implementing the proposed changes, the success will then extend to hedgeable volumes that much earlier and over a 12-month rolling period thereby improving the reduction in overall system gas price volatility. 322 As a result of these anticipated benefits and in lieu of the fact that, with the exception of the customer survey, there are no incremental costs, the company proposes to proceed with the changes identified in table 1 upon receipt of Board approval. In response to a question about why the company does not propose waiting until the Board renders a decision in the Natural Gas Policy Review or Forum, which is expected to proceed at some unknown date in the future, the company witness Mr. Pleckaitis volunteered that the primary reason that the company wishes to go forward immediately following a receipt of a decision in this proceeding is to mitigate price volatility for system gas customers. 323 He added at paragraph 1263 of volume 2 that this is the absolute and total reason, and explained that he felt strongly that the changes should be pursued now as opposed to putting them on hold for an indeterminate amount of time pending the Natural Gas Policy Review. 324 Mr. Pleckaitis reminded parties at volume 2, paragraph 1265, that the company has responsibility to manage system gas and the risk-management program, which has been approved by the Board in the past. Given that customers hold price volatility to be important, Mr. Pleckaitis stated that the volatility that has been experienced over the last three or four years, which is unprecedented and which was not anticipated when the program was originally started in 1995, it is the company's responsibility to address this issue presently and not wait until an unknown date in the future. 325 While the company will certainly accept the Board's judgment as to what is appropriate following the Natural Gas Policy Review, Mr. Pleckaitis stated at paragraph 127 that he sees no reason and, in fact, he thinks it would be wrong from a customer's perspective if we did not act now on an issue that we are experiencing now. 326 The Panel may recall that during some of the cross-examination, I believe it was by Ms. Aitken, that there were some questions asked about what may occur following the Natural Gas Policy Review. Much of it of course, given that we're looking into the future, is crystal-ball gazing. If I may offer some of my own in submission, one potential is, following the Natural Gas Policy Review, that the Board will find that the status quo should continue and that risk management, with its objective of minimizing price volatility, should continue. 327 The second scenario would involve that risk management would continue but that there might be a change in the objective perhaps to that of trying to beat the market. However, given the evidence of RiskAdvisory, Mr. Simard, that that is an inadvisable purpose, then the company would submit that that's not a likely outcome of the future Natural Gas Policy Forum. 328 A third outcome would be that risk management is done away with altogether, and in response to that, it presumably is one scenario where the Board would decide that utilities should no longer be involved in system gas and therefore there would be no need for system gas activities. However, to the extent that the Board does rule that there should remain a default supplier and that the company and other gas utilities should remain in system gas, it's the company's submission, in accordance with the Board's finding in the recent Union Gas decision, RP-2003-0063, that risk-management activities are of benefit to ratepayers. And, Mr. Sommerville, I believe you were involved in that decision. It's the company's submission that it's likely that risk-management activities will likely continue following the forum. 329 The question then becomes will the forum get involved in the minutia of the operations of risk-management activities and start to have the debate between the Mr. Simards of the world, and in the company's submission, that is also, in our view, a remote possibility. 330 Taken in its totality, the question then becomes, Do you await that policy forum given the likely outcome of it, and when you weigh what the crystal ball says in one hand versus what the crystal ball says in the other, it's our submission that there isn't a solid foundation to simply defer recommendations which are, from the evidence before you, uncontradicted in terms of their benefit to ratepayers. 331 Therefore, in conclusion, while all parties are aware of the pending Natural Gas Policy Forum which will occur at some indeterminate date in future and which may or may not look at issues relating to risk management in more or less detail, it remains the position of the company, as expressed by Mr. Pleckaitis at volume 2, paragraph 722, that the proposed changes are needed now and that the company is prepared to accept that the Board may require different changes at some subsequent date. But the bottom line is that there is a need to -- there is no reason, I should say, there is no reason to defer implementation given that there are no incremental costs, aside from the customer survey, and that the uncontradicted evidence is that the recommendations, if implemented presently, will be of benefit to ratepayers. Indeed, when asked whether the company sees any serious implications moving forward with the proposed changes now as opposed to waiting until it receives a decision from the Board following the Natural Gas Policy Review, Mr. Pleckaitis responded at paragraph 1269, that the company sees no implications that are any different than already exist today with the program that it already has in place. 332 Plain and simply, the company submits that there is no compelling justification for delay in implementing the recommendations. 333 Subject to any questions, Mr. Chair, those are the company's submissions in respect to risk management. 334 MS. NOWINA: I have a question, Mr. O'Leary. It's a multiple-choice question. But of course you can go off the multiple choices, if you like. Do you think that the evidence suggests that the changes that you're describing could best be described by one of these, I'll give you the choices: A change in direction in your current risk-management process, a significant change in effect of the program, a minor modification, or, and then there's something else. 335 MR. O'LEARY: Just so I've got them, my options are -- I didn't hear all of the above, but a change in direction, a significant change in direction -- 336 MS. NOWINA: No, significant change in effect, so direction the same but effect is significantly changed. 337 MR. O'LEARY: Minor modification and, D, other. I would assume that in respect of A, Ms. Nowina, you're referring to the objectives of the program and I interpret the word "direction" to meaning objectives. And the proposed recommendations are not intended to implement a change in direction or a change in the purpose of the program, it remains to minimize price volatility in respect of hedgeable volumes. 338 The second option, significant change in effect, I guess the question is, what amounts to significant? There is no doubt that there will be greater or, I should say, improvement in terms of the amount of or levelling out of price volatility, and whether or not that is a significant change relative to the total volumes that flow through the system is one that would be open to debate. The fact is that it is a positive improvement. We would submit, therefore, it is significant and therefore should be pursued. 339 The third was, are they minor modifications? In cross-examination I believe we acknowledged that some of the recommended changes are mechanistic in nature, such as the reduction in the execution windows. You might describe those as minor but appropriate. But taken in totality, we don't view the recommended changes as being insignificant. 340 And I'm afraid I don't have another. 341 MS. NOWINA: That's fine. Thank you. 342 MR. BETTS: Thank you. The Board Panel has no more questions on this particular issue, then. The Board Panel would like to recommend and find out if there's any major objection to a short lunch, we're thinking in terms of 30 minutes. Does that cause a problem for any of the parties? Okay. It looks like everybody is on board with that. Looking at the clock, let's make it 1:30 that we'll reconvene and continue with arguments from Mr. O'Leary. Thank you. 343 One more moment. I'll just confer with the Panel. 344 [The Board confers] 345 MR. BETTS: I just wanted to note, and this is not a suggestion that you need to, but Ms. Persad, the Board Panel will not have any more questions on the arguments that you delivered. If you do want to -- if you have any reason to leave, then please feel free to do so. 346 MS. PERSAD: Thank you. I appreciate that, Mr. Chair. 347 MR. BETTS: We'll break now until 1:30. 348 --- Luncheon recess taken at 1:00 p.m. 349 --- On resuming at 1:33 p.m. 350 MR. BETTS: Thank you, everybody. Please be seated. 351 Thank you everybody and I hope that short break was sufficient. We may all have indigestion as a result of it, but we appreciate your assistance in that. Are there any preliminary matters that arose during the break? 352 PROCEDURAL MATTERS: 353 MR. CASS: There is one, Mr. Chair. I have in front of me what should be, we hope, the completion of undertaking responses from this proceeding. What I have is the responses to Undertakings J.10.2 and J.10.5, together with a covering letter. So perhaps I'll pass that around. 354 MR. BETTS: Thank you. 355 MR. CASS: And that is the only preliminary matter that I'm aware of, Mr. Chair. 356 MR. BETTS: Thank you, Mr. Cass. 357 Did you say, Mr. Cass, that you felt they were the final outstanding undertakings? 358 MR. CASS: That was my understanding. I could be wrong. 359 MR. BETTS: Okay. Perhaps after we break, we could ask the company to just compare your list with the Board's list and just make sure that we are covered in that part. 360 MR. CASS: Certainly. 361 MR. BETTS: Thank you. Any further preliminary matters? 362 Mr. O'Leary, are you ready to proceed? 363 MR. O'LEARY: I am, sir. 364 MR. BETTS: Please do. 365 MR. O'LEARY: Thank you. 366 SUBMISSIONS BY MR. O'LEARY: 367 MR. O'LEARY: The next issue that I will be making submissions in regard to is transactional services which is identified in the issues list as issue 4.1 and 4.2, 4.1 relating to the proposed transactional services sharing mechanism for the next year and 4.2 in respect of the proposal to sell the commodity in the name of the utility, Enbridge Gas Distribution Inc. 368 Before I turn to those issues specifically, I would like to first identify certain factual observations which we submit are conclusions that the Board may reach based upon the evidence before it. First, it is clear from the evidence that by undertaking transactional services, both with and without the bundling of the commodity, there has been a substantial benefit to ratepayers. In fiscal 2003, the ratepayer benefit was 13.55 million. The year-to-date 2004 total as identified in response to Undertaking J.4.1 is 13.18 million. 369 The second important factual observations is that the bundling of the commodity with the sale of the utility's excess assets has significantly enhanced transactional services' gross margin. One need only compare the budgets for the years 1998 through 2002, when bundled transactions were not undertaken, to the results achieved in fiscal 2003 and to date in 2004. Again, returning to the response to Undertaking J.4.1 which you may have visualized as -- that was the VECC template with all the various years and -- broken down the various shares by the ratepayers and the shareholders. 370 In answer to that undertaking, the company listed the transactional services results over those years. For the period 1998 through 2002, the gross margin from transactional services ranged from 5.69 million in 1998 to 9.36 million in 2002 with a high of just over 14 in 2001. 371 By comparison, in 2003, the gross margin related to commodity-bundled transactions alone was 10.5 million and it's 13.6 million in respect to fiscal 2004 to date. The conclusion we submit that should be reached is that bundled transactions are a source of additional significant benefit to ratepayers. 372 Third, to date, all of the risks to the commodity asset with bundled transactions have been borne by Enbridge Gas Services. Ratepayers have neither been exposed to any risk associated with the commodity nor charged any fee for credit costs. While the risk of default by approved creditworthy counterparties was described in evidence as being small, the undisputed fact is that risk exists and that while the company has been successful in avoiding any costs relating to counterparties failing to perform which was the company's evidence at Exhibit A2, tab 5, schedule 1, everyone is aware the publicized recent failure of a significant player which proves this risk is real. 373 As noted by company witness, Mr. Brennan, of the 285.5 million in bundled transaction revenues generated in 2003, 275 million related to the commodity. Enbridge Gas Services alone was exposed to any default in respect to this amount. 374 The fourth factual observation and the conclusion we invite you to reach is this: Based on the company's evidence in this proceeding, it is clear that the only motivation behind the company's proposal is one of fairness; namely, that there should be a sharing of credit costs and risks proportionate to the benefits of the transactional services activities undertaken. The company has proposed that the commodity portion of bundled transactions be undertaken in the name of Enbridge Gas Distribution not EGS. This change was described in evidence as akin to a self-insurance. This change would not materially increase or decrease the expected recovery by ratepayers, nor the shareholder relative to the existing situation because, as it is stated in the evidence, it is the most cost-efficient means of proceeding in that Enbridge Gas Distribution would incur little or no credit costs. 375 From the perspective of the shareholder, it would be revenue neutral in that it would not become a source of additional earnings for the shareholder. 376 A final factual observation we wish to submit and invite you to conclude relates to the inherent fairness of the existing mechanism, the existing sharing mechanism as it exists. The sharing mechanism as proposed by the company contemplates a guaranteed amount to ratepayers that is embedded in rates. 377 Perhaps I should depart just at this point and indicate that in our submission, there is a balancing of the benefits and the risk when the Board ultimately should make a determination as to what that amount which should be embedded is rates is. We invite the Board to consider the impact on the ratepayer and compare that to the impact on the shareholder when the decision is made as to the amount, should you decide to embed a number into rates. 378 If we start with a particular number that is the same and consider two scenarios, one where the amount embedded into rates is 8 million, and a scenario where the amount embedded into rates is higher, the benefit to the ratepayer is that they will see in the fiscal 2005 test year the benefit of that gross margin; whereas, if it is a higher number, they'll see that amount sooner, but in effect, if the amount is kept at the 8 million, the only negative from the ratepayer's perspective is that there has been a deferral of that benefit in that there is the sharing mechanism of the 75/25 which will be recorded in the transactional services deferral account that will be cleared to rates in a subsequent proceeding. 379 By contrast, where there is an amount which is embedded in rates which is higher than what the company is proposing, you're putting the ratepayer -- I misspoke myself, you're putting the shareholder at risk in that if those revenues are not achieved then you have already the benefit automatically guaranteed through to the ratepayer and it's the shareholder that bears the risk. So you're comparing what amounts to the negative on the one hand which is the simple deferral of gross margin versus the risk to the shareholder which is that if the transactional services gross margin does not achieve that amount that is guaranteed, which some intervenors may suggest should be higher than 8 million, that it's totally to the account of the shareholder. 380 I should remind you that in the formula, in addition to the amount that is guaranteed to ratepayers, there is also an amount that comes out of the shareholders' share which is in respect of the operations and maintenance cost of the transactional services. To the extent that the aggregate of these amounts is not generated from transactional service sales, the difference is entirely at the cost of the shareholder. 381 Given this, the company's proposal to once again guarantee to ratepayers 8 million if bundled transactions continue and 4.5 million if they do not, the company submits, is appropriate and fair. 382 Turning to issue 4.1 specifically, which relates to the sharing mechanism, the company's proposing, as I just indicated, the continuation of the sharing mechanism, in effect, in fiscal 2003 and 2004 subject to a reduction in the guarantee to ratepayers in the event that bundled transaction are continued. It's the company's submission that ultimately the Board did approve the sharing mechanism for those years and therefore it is a fair mechanism and one that can be relied upon in future. 383 Specifically, this sharing mechanism would involve the first 8 million of the gross margin being embedded into rates. The next 2.7 million would then go to the account of the shareholder. Out of this amount, the expected O&M of 700,000 would be deducted. Any remaining gross margin above the aggregate of these amounts would then be shared on a 75/25 percent basis in favour of the ratepayers. 384 In the event that the Board rules in this proceeding that the commodity cannot be undertaken in the name of the utility, the company requests that the Board authorize EGS to charge back to EGD the credit costs associated with commodity transactions undertaken in the name of EGS. In such situations, a fee for credit costs would be deducted from gross margin. 385 In the event that bundled transactions are discontinued, the company proposes that the guaranteed amount to ratepayers which is embedded into rates be fixed at 4.5 million. There is a simple reason for this decrease in the amount guaranteed to ratepayers from 8 million to 4.5 in the event that the bundled commodity transactions do not continue. 386 Bundled transactions, as I indicated earlier, made up more than half of the transactional services gross margin in fiscal 2003. Under the non-bundled commodity transactions sharing mechanism proposal where the ratepayers would have the guarantee of 4.5 million, the next 1.3 million above that would be to the account of the shareholder. From that amount, the O&M would be deducted of an estimated 700,000, leaving the actual share to the shareholder of 600,000. Any gross margin above the aggregate of these amounts would then be shared 75/25 percent in favour of the ratepayers. 387 Perhaps I could use, for the benefit of the Board, several real-world examples of how these might play out. Again, using the company's response to Undertaking J.4.1, you will note that in fiscal 2002, the gross margin from transactional services was 9.36 million. If you deduct from that amount the ratepayer guarantee of 8 million and you're left with a remainder of 1.36 million and then you deduct again the O&M associated with transactional services, it leaves a margin to shareholders of $660,000. And I use that because that is an actual historic figure, and applied the mechanism of that to demonstrate the fairness of how the sharing mechanism would work in future if that was the ultimate result of the transactional services activities. 388 If we used an example where, assuming that the Board does not allow bundled transactions to continue, and we're talking about an amount being embedded into rates of 4.5 million to the guarantee of ratepayers, and we use the example from 2003 which is the amount that relates solely to transactional services without the bundled commodity, that historic amount is 7.6 million. You would deduct from that the amount embedded into rates in favour of the ratepayers of 4.5 million. It leaves 3.1 million. You deduct, then, what the company proposes to be the guarantee to the shareholder of 1.3 million and that would leave a remainder of 1.8, which, again, would be split 75/25. The net result of that is that after you deduct the O&M portion of the -- which comes out of the shareholders' 1.3 million, the net result is that the shareholder would recover 1.05 million, just a little over a million dollars, versus a total recovery by the ratepayers of 5.85 million. 389 I've walked you through those examples as, hopefully, a demonstration of the fairness of the sharing mechanism under either the with-commodity or without-commodity proposal. 390 Now, in terms of why a downward adjustment is needed should bundled transactions be discontinued, as I've indicated, the reason for it is simple and straightforward. 391 The gross margin related to bundled transactions is significant. In fiscal 2003, and likely in 2004, gross margin from bundled transactions will exceed the gross margin from transactional services that did not involve the commodity. In fiscal 2003, the gross margin generated by bundled transactions was 10.5 million of a total 18.1 million, which is about 58 percent of the total transactional services gross margin. 392 By comparison, reducing the guarantee to ratepayers from 8 million to 4.5 million, which is a decrease of 3.5 million, that represents or amounts to a decrease of only 43 percent. Stated differently, relative to the difference between the margin generated by bundled transactions and non-commodity transactions in fiscal 2003, the proposed reduction in the guarantee to ratepayers from 8 million to 4.5 million is disproportionately small. The proposed guarantee of 4.5 million can, therefore, hardly be said to be unfair. 393 The only other issue which might affect the bottom-line recovery by ratepayers is in the event that the Board orders that the commodity transactions continue in the name of Enbridge Gas Services but permits appropriate credit costs to be charged back against gross margin. It is noteworthy that even under this scenario, the 8 million guaranteed to ratepayers remains embedded in rates. The effect of this is that these credit costs would have, in effect, reduced the gross margin available to pay O&M costs and the shareholders' base share prior to any amounts being included in the transactional services deferral account. 394 In other words, the shareholder, once again, assumes all of the risk that if an insufficient margin is generated to match the amount guaranteed to the ratepayers, O&M costs and credit-risk charges, the shortfall is entirely to the account of the shareholder and it receives no benefit. You may recall that there was some discussion during the oral portion of the hearing about how these credit charges would be deducted from the gross margin. The fact that you've embedded an amount into rates means that that -- if you don't achieve that number, then those credit costs are all in the account of the shareholder. 395 The other important point to highlight is the fact that this also means there is a sharing of credit costs, and that these costs will reduce the gross margins which would otherwise have been recorded in the transactional services deferral account which would ultimately be shared on a 75/25 percent basis. Each of the shareholder and ratepayer would see their incremental portions in the TSDA reduced by their proportionate share of the credit costs. As noted earlier, while the shareholder could still end up receiving no benefit and paying all of the costs, at least there is a prospect of the sharing of such costs under this alternate proposal. And as I indicated in the beginning of my submissions, we submit that that is fair and one of the motivations behind one of the recommendations that the company's putting forward. 396 MS. NOWINA: Mr. O'Leary, could I interrupt you for a second? I didn't quite get the last section where you reduced the credit costs or took the credit costs, and then what portion it came out of where it came out of the 8 million or afterwards. Could you run that by me one more time? 397 MR. O'LEARY: I will try, and it may be because I misworded it. I'll try to do it in different wording. And that is that if -- assuming the Board approves that $8 million is embedded into rates, that goes into rates in fiscal 2005, a reduction, effectively, in rates of $8 million. If, hypothetically, then, assuming that EGS continues to deal with the commodity in its name and the Board allows credit costs, that amount is not caught in some separate account. If the actual transactional services activities only generate $8 million or less, there are no monies, then, left to pay these credit costs. So, in effect, it means that because the amounts are already embedded into rates, until you've gone above the amount that is embedded into rates to the benefit of ratepayers, those credit costs are not deducted until that point is achieved. 398 MS. NOWINA: So the credit costs are deducted at the end from the margin? 399 MR. O'LEARY: As soon as you exceed the amount embedded into rates, yes. 400 Turning to issue 4.2 which is the company's request for authorization to undertake the commodity portion of bundled transactions in its own name, while several alternatives of this were discussed in evidence as noted in the company's prefiled evidence at Exhibit A2, tab 5, schedule 1, page 6, at paragraph 24, it is the company's view that this is the most cost-effective approach and it's involving Enbridge Gas Services to conduct commodity transactions in the name of the utility, Enbridge Gas Distribution. 401 Presently the commodity portion of bundled transactions has been undertaken in the name of EGS as noted in the company's prefiled evidence, EGS has indicated a reluctance to enter into commodity transactions in its own name by reason of the credit costs and the risk of any inability to recover bad debt. 402 While the company's witnesses admitted during the oral portion of this proceeding that the risk of default by counterparties is small, the logic and fairness of transferring this risk for the cost to those parties who benefited from the activity, we submit, is very compelling. 403 This being said, it was also the evidence of the company at Exhibit A2, tab 5, schedule 1, paragraph 26, that the risk would continue to be appropriately managed regardless of whether the commodity transactions are undertake in the name of the utility or remain within the name of EGS with the ability to charge back credit costs. As stated under cross-examination, Mr. Whelen, the vice-president and treasurer of Enbridge Inc. and the treasurer of Enbridge Gas Distribution in response to a question about whether EGS would be a little less vigilant in regard to the risk of default by counterparties relative to EGD, Mr. Whelen had the following to say and I quote. 404 "I can speak from a risk-controlled perspective and as somebody monitoring in Mr. Jarvis's business, absolutely not. He has an agency responsibility under that agreement to be vigilant with respect to the risks that he is undertaking. So we apply the same due care and attention that we would to any other business." 405 As in the past, the company would continue to transact only with approved creditworthy counterparties which are rated triple B minus or greater and that's transcript reference Volume 4, paragraph 683. 406 The evidence of the company's witnesses during the hearing was that the risk probability factor associated with such approved creditworthy counterparties range between .01 and .05 percent. Transcript reference is paragraph 684 and 789. It is therefore appropriate to say that the risk which Enbridge Gas Distribution would take on by undertaking bundled transactions in its own name would be very small. 407 We submit that there is a sufficient record for the Board to make a finding to that effect. 408 As noted in the prefiled evidence at paragraph 24, given Enbridge Gas Distribution's credit position, a line of credit or a parental guarantee may not be required and even if it were, the costs would be lower than if EGS had to provide a line of credit. In other words, again as I indicated or submitted earlier, the most cost-effective means of proceeding with bundled-commodity transactional-service sales in future is by allowing the company to conduct the commodity transaction in its own name. 409 Should the Board not authorize EGD to undertake commodity transactions in its own name, the alternative is for EGS to be appropriately compensated for its credit risk costs. It was the evidence of the company's witnesses during the proceeding that they estimate these costs to be around $2 million. Mr. Whelen stated in evidence at paragraph 116, Volume 4, that this figure was developed from several perspectives and I quote: 410 "If one was to look at the stand-alone cost of a third-party credit provider coming up with a letter of credit to provide that amount," he's referring to the - paraphrasing here - the 100 million maximum exposure, and starting with the quote again: 411 "... the other way it was looked at was in a more theoretical manner as to what amount of economic capital using some statistical analysis would be required to reserve against some contingent unexpected loss. That's where in one given year there would be failure of one or more of the counterparties to these transactions, and using that approach deriving a return offer of that number." 412 At transcript reference Volume 4, paragraph 1084, Mr. Whelen also stated that if the company's estimate of the $2 million fee isn't sufficient, he was confident that the company could get an independent third party to verify the reasonableness of an appropriate charge in light of what a financial institution or other guaranteeing entity would require to carry on this sort of business. While the company is confident that a fee of approximately $2 million is fair and appropriate in response to a 60-day, $100 million exposure, it should be remembered that the company's preference is that the commodity portion of the bundled transaction be undertaken in the name of the utility which eliminates more or less the concern about the credit cost fee. 413 Another important matter which the company confirmed in both its oral testimony and prefiled evidence relates to the purpose of offering bundled transactional services. Bundled transactions are used to generate transactional services revenue where there would otherwise be no opportunity to sell transactional service alone for similar value or to capture certain short-term intra-day opportunities. The company stated that it will only enter into commodity transactions when it can do so in conjunction with other transactional services such as storage and transportation thereby increasing the value of the transaction. And the evidentiary citations in support of those statements are the response to CEED Interrogatory No. 2, the company's prefiled evidence at paragraph 18 of Exhibit A2, tab 5, Exhibit 1, and the company's response to Board Staff IR No. 11. 414 It is the company's evidence that the offering of bundled transactions is partly the result of the fact that there is less liquidity in natural gas markets than previously available. It was noted in the company's response to Board Staff IR No. 11 that: 415 At times, no counterparty could be found to monetize available service offerings, or if one could be found, the margin expectation of the counterparties were such that fair value could not be captured by Enbridge Gas Distribution. 416 I should also take a moment to briefly underscore what the company has stated in evidence about the increasingly important issue of credit costs and the risk of default. The company went into great detail in response to Board Staff Interrogatory No. 13 providing background and an explanation about credit exposures and the costs of credit. While I do not propose to go on to the company's response in great detail, I trust it would be helpful to highlight how the company established its maximum exposure. 417 The company undertook an examination of expected peak levels in transactional services activity to estimate the total credit exposure which is required to facilitate commodity activity if bundled with transactional services. The company determined that it needed to establish credit to potentially purchase up to 100 million of gas supply to facilitate asset optimization. Likewise, the company will need to establish security to potentially create 100 million plus expected margins of accounts receivable. This 100 million is based upon a 60-day credit exposure. The proposed $2 million fee in the event that EGS continues to undertake commodity transactions in its own name, reflects the magnitude of this exposure. Indeed, it is noted in the company's response to Undertaking J.4.3 the maximum two-month credit exposure in fiscal 2003 was 113 million. This confirms the magnitude of the exposure and that it is real. 418 One related matter to the transactional services issue which is on the issues list which I will also address is issue 13.2, which relates to the proposed change in year-end and the implications from a transactional services perspective for the stub period of October 1st, 2005 to December 31st, 2005. The company proposes that the transactional services sharing methodology be extended for the stub period by prorating the gross margin ratepayer and shareholder guaranteed amounts which the Board approves in this proceeding over the last quarter of calendar 2005 and then applying the 75/25 percent split for any remaining gross margin. 419 Perhaps I could run through a quick example. Should the Board approve a guaranteed ratepayer share for fiscal 2005 of 8 million or 4.5 million, depending upon whether bundled transactions continue, then one-quarter of this amount would become the ratepayer guaranteed base for the stub period. Should the Board authorize EGS to charge back credit costs associated with undertaking commodity transactions in its name, such credit costs during the stub period would also be deducted following the -- after the amount that's embedded into rates. 420 The shareholder base share would then be one-quarter of either 2.7 million, which is the proposed shareholder base rate with commodity transactions continuing, or one quarter of 1.3 million in the event that commodity transactions are discontinued. 421 From these amounts, from the amounts that are guaranteed to the shareholder, O&M costs for the stub period would be deducted. Any remaining gross margin would then be split 75/25, again in favour of ratepayers. 422 Given that the sharing mechanism for the stub period will depend upon the Board's ruling in respect to the test year, the company submits that there should be no issue relating to the appropriateness and the reasonableness of continuing what would then be Board-approved methodology for an additional three months. 423 In conclusion, Mr. Chair, the company invites the Board to once again find that the sale and use of the utility surplus assets has and continues to be of great benefit to ratepayers, and that these benefits have been significantly enhanced with the bundling of the commodity with transactional services -- with traditional transactional services. 424 The company asks the Board to approve that such services continue both with and without bundling with the commodity; however, the company asks that the relatively minor risk of default by a transactional service counterparty and any credit costs be assumed by the utility by undertaking such activities in the name of Enbridge Gas Distribution. 425 In the alternative, the company submits that if such commodity-based transactions are to continue in the name of EGS, that it should be entitled to charge for its credit risk costs pursuant to said fee estimated at $2 million. And I should add that the company would be content, if the Board should not be inclined that $2 million is the right fee, as adding a condition to its order that the company retain an independent consultant to determine and calculate the right fee. 426 Those are our submissions, Mr. Chair. 427 MR. BETTS: Thank you. 428 [The Board confers] 429 MS. NOWINA: I have one question and it's not multiple choice. I'd just like to direct me in the evidence if it exists, and if it doesn't, that's fine, I'll try and find it myself, for something like the VECC template, K.4.2, Exhibit K.4.2, where it shows the result -- the end ratepayer benefit and shareholder benefit with a $2 million credit cost paid from the shareholders to -- or the ratepayers to EGS. 430 MR. O'LEARY: I don't think that in the evidence -- in fact, I think the template or the evidence may have suggested that it is coming off the top. 431 MS. NOWINA: And it shows it as $500,000, at least in the version -- 432 MR. O'LEARY: That would be just for the stub period, would it not? Perhaps we should go to it. 433 MS. NOWINA: It says it applies to the forecast. It might have been to the actual cost. It's 50,000? So that's actual cost. That's right, it shows it as 50,000, which would be the actual cost. 434 MR. O'LEARY: I have, Ms. Nowina, a copy of the -- this is the VECC template which was the response to the company Undertaking J.4.1, and if I could take you to page 2 of that, with the 2005 forecast, there is the .05 identified as a deduction from credit costs. Our understanding as to how it would work is that that is going to be deducted after the amount that is embedded into rates, because that's simply the way it would have to work. 435 MS. NOWINA: So it wouldn't work like this? 436 MR. O'LEARY: I think the appearance in the template is a little misleading. Simply that if you have guaranteed into rates an amount, that has been included in rates for the test year. And if the company does not achieve that amount, that amount has already been included and the ratepayers have received the benefit of that amount already. So it is only and can only be the amount over and above that from which you would deduct the credit costs as a matter of fact. 437 MS. NOWINA: Okay. Thank you. 438 MR. SOMMERVILLE: That would also apply to the company's preferential share, would it not? You would have to go through the ratepayers' preferential share, then the company's preferential share, and then the costs would start to be appropriately allocated. 439 MR. O'LEARY: I would understand that it would be deducted -- my understanding from the evidence was that it was to be deducted from the gross margin, so as soon as you've exceeded the amount that's embedded into rates, it would be deducted at that point. 440 MR. SOMMERVILLE: So what you're suggesting is only the ratepayer portion, then; is that right? 441 MR. O'LEARY: Yeah. Well, it's only the ratepayer portion which is actually embedded. 442 MR. BETTS: I have a couple of questions as well. 443 Mr. O'Leary, you referred to the fact that the Board had approved the sharing mechanism. Perhaps you can help me. Was -- and you referred to 2003 as the -- was that one of the items that was part of the settlement agreement? 444 MR. O'LEARY: Yes, sir. And I don't mean to overstate the extent of the approval and I don't mean to be presumptuous in that regard. It was part of the settlement agreement there, but ultimately it is within the Board's prerogative to reject a settlement proposal and that settlement proposal was approved. Presumably there was sufficient evidence to find that that produced just and reasonable rates. 445 MR. BETTS: Thank you. And, in fact, that relates to the acceptance of the Board's -- the acceptance of that settlement agreement by the Board. 446 MR. O'LEARY: Yes, sir. 447 MR. BETTS: With respect to that, there was a change in the shareholders' share in that mechanism from 10 percent to 25 percent, I believe. If there were a $13 million amount, or something in that order of magnitude, I haven't done the arithmetic, that was to be shared, it seems to me that the increase in the shareholders' share is roughly about $2 million, in that neighbourhood, a change from 10 percent to 25 percent. 448 MR. O'LEARY: My understanding of the way the methodology worked prior to that involved a 90/10, but it was in respect of the budgeted amount which would be fairly or conservatively set, and after that amount, there was a different sharing formula. Under the new mechanism, we have this amount that's embedded into rates so it's a guarantee there regardless of the success of the sales of transactional services. So I think that we are dealing with two different items here, one that has a greater risk, and there's a recognition of that in the formula, versus what previously existed. 449 MR. BETTS: Thank you. One point, and I don't recall you addressing it in your argument, and if you choose not to at this point, that's fine, but you've referred to basically the benefits associated with the bundling approach that are achievable or at least that would apply to the ratepayers, what benefits there are to that group and obviously to the shareholder as well. Did you at any point address, or do you care to address, the effects that that might have on the competitive marketplace? 450 MR. O'LEARY: Sir, I anticipate that that will be raised by some intervenors in their argument and it had not been my intention to take up the Board's time with it at this point but rather to deal with it in reply. 451 MR. BETTS: That's quite acceptable, Mr. O'Leary. 452 MR. O'LEARY: Our position simply is that there is no evidentiary basis to make a finding that there is a negative impact on the competitive market, but I would prefer to respond in greater detail if need be in reply. 453 MR. BETTS: Thank you. That's quite acceptable. 454 Ms. Nowina. 455 MS. NOWINA: Just one more and I'm just going back to the same thing. I'm simply trying to understand, Mr. O'Leary. Do you have volume 4 of the transcripts with you? 456 MR. O'LEARY: Actually, I do not. 457 MS. NOWINA: I hate to have to quote the whole thing because I'm afraid that I will take it out of context and I will lose something, but there is a -- Mr. Janigan was talking to Mr. Brennan and Mr. Brennan responded on the issue of passing on the credit costs if EGS should continue to purchase the commodity, and the reference is Volume 4, it's paragraph 475 which is Mr. Brennan's response. And his last sentence, he goes through a description of direct costs that come off the top before the margin, his last sentence is: 458 "So I would see these credit costs being included as part of direct costs which would be taken right off the top as a cost of doing the business as well." 459 Now, isn't that just like it is in the VECC template? 460 MR. O'LEARY: I do remember that evidentiary reference, Ms. Nowina, and my submission is one simply of practicality. That is, that if the Board orders that an amount be embedded into rates for fiscal 2005, there is a benefit that automatically flows through and that rates would be less than would otherwise be the case, and the company is not asking for the 2 million to come off the top of the 8 million so the impact of it really is that it comes off the margin after the embedded amount. 461 MS. NOWINA: I guess what you're saying is if the overall margin is less than 8 million, the ratepayers get 8 million in any case? 462 MR. O'LEARY: Absolutely, that's correct, I wish I had said it that way. 463 MS. NOWINA: Thank you. 464 MR. BETTS: One final question, I did have it here and I just overlooked asking it. 465 With respect to the $2 million estimate, if the Board were inclined to accept that, would the company see that as being immediately placed into rates or how would it be handled? And I will be asking you the converse question which is: If the Board were willing to accept the proposal of a third-party review of the appropriateness of that amount, how would that actually impact rates in either 2005 or 2006 or what would be the mechanism? 466 MR. O'LEARY: Sir, I do think that in Mr. Whelen's evidence that the $2 million figure was given as an estimate and there are, it was anticipated that those credit costs would not be actually impacting rates in fiscal 2005, and in the event that you found that an independent consultant was appropriate to come up with the credit cost figure, then those amounts would similarly be dealt with in a subsequent proceeding. But again, I remind the Panel that the company's preference is for the commodity portion to be undertaken in the same of the utility and then we need not deal with that issue at all. 467 MR. BETTS: Thank you. Thank you very much, Mr. O'Leary, that concludes the questions from the Board Panel. 468 MR. O'LEARY: Mr. Chair, if I might, just in speaking with members of the company, in respect of should the Board ultimately order that the commodity would be undertaken in the name of EGS, be allowed to charge back the credit costs, you question about what would be the appropriate treatment of those credit costs, the suggestion was that in the event that such an order was made that the Board establish a variance account that would be appropriate so we would record those amounts once determined through the consultant or if you should order the 2 million as an appropriate fee, and then that would be cleared through the rates in the subsequent proceeding. That, we believe, would be the appropriate accounting treatment for those costs. 469 MR. BETTS: Thank you. And that, in fact, concludes, then, the Board's questions on that matter and the answers. 470 Are we ready to proceed with the next issue? 471 MR. O'LEARY: We are, sir, and this will be a little briefer. I'm dealing next, my last area, last submission is dealing with demand-side management. As was noted during the course of the proceeding, there was in effect a complete settlement of issue 10.1 which relates to the DSM plan volume target and the O&M budget. All parties agree to a 12-month volume target of 76.9 million cubic meters and a 12 month DSM budget of 14.8 million. 472 In addition, it was agreed by all parties and specifically referenced in the settlement agreement that the company would spend no less than 300,000 on an efficient large boiler program with an associated volume target of 2.1 million cubic metres for this program. The settlement agreement also requires the company to file a longer term strategic DSM plan on or before January 1st, 2005 which will address, amongst other matters, market transformation initiatives. 473 There was also in effect a complete settlement in relation to 10.2 which relates to shared savings mechanism incentive scheme for 2005. All parties agreed that the SSM, LRAM and DSMVA methodologies would continue for the test year on the terms previously approved for use in the RP-2002-0133 proceeding which related to fiscal 2003 with an additional incentive for high-efficiency window market transformation program which was also agreed to as part of the settlement. 474 Again, all of the above was agreed to by the parties to the proceeding. The sole remaining issue, as you know, during the test year from a DSM perspective, is the proposal by Pollution Probe which relates to the development of a commercial, institutional and industrial large boiler market transformation program and a shareholder incentive which they asked that the Board order be done prior to January 1st, 2005, and that a budget increase or a deferral account be created for the costs associated with such direction. 475 The company's position which is set out in the settlement agreement is as follows: 476 Enbridge takes the position that Pollution Probe's proposal would require additional funding to overcome budget constraints, market barriers and to pay for additional valuation work. Also, if additional monies are to be expensed for this program, it should be added to the budget and not recorded in a deferral account. 477 I should state at the outset that the company is pleased that it was able to effect a near-complete settlement in respect of all DSM test year issues. However, despite this near complete-settlement the company offers the following comments in the hope that it will assist the Board in its consideration of the proposal by Pollution Probe. As the Board has probably already noted, the company had proposed in its prefiled evidence to focus some of the DSM budget in the test year on high-efficiency boilers. At Exhibit A7, tab 2, schedule 1 of the prefiled evidence, there's a description of these programs and I direct you to pages 8, 9, and 11. At Exhibit A7, tab 2, schedule 6, page 3, the company lists the program assumptions associated with its proposed high-efficiency boiler program. Accordingly, the issue before the Board is not whether the company will undertake a program or programs which promotes high-efficiency boilers, but whether additional budgets should be made available for the company to expand its efforts in 2005 in the context of a market transformation program dedicated to such boilers. 478 Again as I noted earlier, I remind you that the settlement agreement also identifies in the fourth paragraph that the company has agreed to expend 300,000 of the 14.8 million of its DSM budget on efficient large boilers. 479 It should also be noted that the settlement agreement obligates the company in respect of the strategic DSM plan that I identified earlier in my submissions, but the agreement does not specify that the strategic plan must address a high-efficiency boiler market transformation program and shareholder incentive for such a program, one option available to the Board is for it to simply require the company to include in its strategic plan the company's proposal for the development of a large boiler market transformation program and incentive mechanism as advocated by Pollution Probe. 480 Given the time that the company believes it will require to develop a plan of this nature, perhaps that is the most prudent and practical course. As you may recall, it was the evidence of Ms. Clinesmith at Volume 6, paragraph 92 of the transcripts, that the company will require four months after the Board renders its decision in this matter. And her reasoning behind that, and these are Ms. Clinesmith's words, are: 481 "Those months are necessary" and I quote "to develop a program with targets and time lines and an implementation strategy which would be developed in cooperation, conjunction and consultation with the various intervenors, manufacturers, distributors, consulting engineers that are active in the market." 482 So the development of a credible market transformation program and one which has a reasonable prospect of success, we submit, requires consultation with appropriate intervenors, manufacturers and distributors, and this cannot be completed overnight. 483 Assuming that the Board hands down a decision in this proceeding at some point later this summer, it appears that the date by which the company would be in a position to file its strategic plan, which, under the settlement agreement, is January 1st, 2005, is remarkably close to the timing by which time it would be capable of responding to a Board directive, come up with the Pollution Probe requested market transformation plan. 484 In the event that the Board concludes that a high-efficiency boiler market transformation program should be put into effect during the test year, then the company wishes to make the following comments: 485 As noted from the settlement agreement, additional budget will be required for any large boiler transformation program beyond the budget that is already included in the settlement agreement. No budget, nor performance target has been contemplated by the company in respect of the market transformation program which is proposed by Pollution Probe. There is simply nothing included in the settlement agreement as it now stands for such a program. 486 Accordingly, some mechanism must be approved for the recovery of the costs associated with this additional program. The company expressed a preference for adding such monies to the budget over recording such expenditures in the deferral account. As noted by Mr. Ryckman in the proceeding, at volume 6, paragraph 90 of the transcript, the company is concerned that by including such costs in the deferral account, it would create uncertainty as to the company's ability to subsequently recover these amounts; however, in the event that the Board orders the establishment of a deferral account as proposed by Pollution Probe, the company requests that the order include a proviso that monies approved for expenditure in relation to the high-efficiency boiler market transformation program be cleared through to rates at the first practical opportunity subsequent to the end of the test year. 487 The remaining DSM issue relates to the impact of the company's proposed change in its year-end. For the -- 488 MS. NOWINA: Mr. O'Leary, before we go on to that one, can we ask questions about the boiler program? 489 MR. O'LEARY: Certainly. 490 MS. NOWINA: So your suggestion, I guess, or one of the possibilities is to ask you to include looking at the boiler transformation program as part of the plan that you will be producing for January in any case. 491 MR. O'LEARY: That's correct. 492 MS. NOWINA: Now, that plan that you will be creating in January in any case, do you expect that plan to be implemented and costs to be incurred during the fiscal year? 493 MR. O'LEARY: In -- no, my understanding is that the strategic plan would be presented and filed January 1st, 2005, but the implementation of items in it, other than this market transformation program proposed by Pollution Probe, would not, in fact, take place until the next fiscal year. 494 MS. NOWINA: So 2006. 495 MR. O'LEARY: Yes. 496 MS. NOWINA: So if it was included in the plan, as all other aspects of the plan, there would be no need for a mechanism to record costs to it because you would not imagine incurring the costs -- 497 MR. O'LEARY: That's correct. The issue is -- 498 MS. NOWINA: - unless we ordered you to do otherwise. 499 MR. O'LEARY: Unless you ordered the market transformation plan to be put in effect at some point after the plan is approved by the Board. 500 MS. NOWINA: Thank you. 501 MR. O'LEARY: In respect of the impact of the company's change in year-end, for the period commencing October 1st, 2005, ending December 31st, the company proposed in its prefiled evidence that the volume target and budget for the stub period be set at 25 percent of the amounts agreed to in the settlement agreement. Specifically, again, the volume target would be 19.2 million cubic metres and the O&M budget would be $3.7 million for the stub period. 502 The Board will recall from the prefiled evidence and the evidence of the company witness who appeared in respect of year-end changes, Mr. Ryckman, that it has been the company's experience that it achieves on average only about 15 percent of the annual volume savings during the period October through December. While this number would have to be increased slightly to reflect the budget equal to 25 percent - I believe you'll recall that the filing indicated that the company doesn't normally spend 25 percent of its budget during that quarter as well - when you still adjust for that, the historic precedent is that the company does not and has not achieved 25 percent of its volumes during that quarter. 503 It is therefore appropriate, we submit, for the Board to conclude and accept Mr. Ryckman's evidence that the 25 percent volume target for the stub period which the company is proposing is an aggressive target. 504 The company has also proposed that the LRAM, the DSMVA accounts, and methodologies agreed upon for the test year continue in the stub period, and there does not appear to be any opposition to that. 505 In regard to the shared savings mechanism, the company proposed in its prefiled evidence a methodology which it believed would address any concerns that intervenors might have about the potential for gaming, and that such intervenors might see an opportunity for the company to shift volumes from the test year into the stub period to become eligible for an incentive payment. 506 To put such fears to rest, the company proposed three simple rules: 507 The first was, in the event that the company is successful in the test year and also in the stub period, the company would be entitled to receive an SSM payment based upon the formula for that particular period. 508 The second rule -- I should stop there and should add that there there's no advantage or disadvantage to the rule that was proposed in that whether you proceed to look them independently in that scenario or combine the two, the math works out the same. Whether you look at both the 12-month period or the stub period separately, or you combine the volumes and develop an SSM based on either scenario, the number works out mathematically the same. 509 The second rule that the company proposed was, in the event that the company generated sufficient TRC savings in the test year but not in the stub period -- and in this situation, it would be a business-as-usual under the settlement agreement. By that I mean it provides that if the company achieves the target volume of 76.9 million in the 12 months, then the company is entitled to as SSM, as it would under the settlement agreement which all parties agreed to. And the fact is that if it doesn't achieve sufficient volumes to generate an SSM during the stub period, it's disentitled to claim an SSM for that period. So it truly is just business as usual. 510 The third rule relates to the scenario where the company fails to generate sufficient volumes to make it eligible for an SSM incentive in the 12 months but then does achieve sufficient volumes during the stub period. It is this scenario in which the company believes intervenors might create -- or that might lead to intervenors believing that there was an opportunity for gaming and for which the rules that we've just put forward were developed. 511 The company submits that by adding the agreed-to target volumes for fiscal 2005 to the stub period volumes, it removes any opportunity to game. The company would be entitled to receive an SSM incentive payment only if it exceeds the aggregate of the volume targets for the two periods, which is 96.1 million cubic metres. Moving volume savings forward from the 12-month period into the three-month stub period with this rule in place would achieve nothing as the SSM would be calculated on the aggregate of the two periods. 512 As the Board may recall, Mr. Ryckman stated on several occasions during his cross-examination that the company does not participate in gaming. He stated that at volume 11, paragraph 673. I should also point out that the SSM incentive payment is calculated at the conclusion of the period of time in question, following a review by an auditor and with the input of the DSM consultative. It is also subject to review by this Board when the company proposed clearing the incentive payment through to rates. All of this scrutiny should give all parties a high degree of confidence in the integrity of the process. 513 In the end, Mr. Ryckman indicated while under cross-examination that the company would be very content to treat the two periods separately, that is, that the SSM relating to the test year be quantified and dealt with independent of any SSM earned and calculated during the stub period. He said that at paragraph 609 of volume 11. Given that the DSM activities in each of the periods in question will be scrutinized fully, the company submits that this would be a result which would be in the interests of all parties and the public, and the company does not oppose such a finding by this Board. 514 Those are our submissions with respect to the DSM. 515 MR. BETTS: The Board Panel has no questions on that particular argument, thank you. 516 MR. O'LEARY: Thank you, Mr. Chair. 517 MR. BETTS: And that concludes the portion you are arguing, Mr. O'Leary? 518 MR. O'LEARY: It does, sir. 519 MR. BETTS: Thank you very much. I appreciate your arguments. That will help the Board. 520 Mr. Cass. 521 FURTHER SUBMISSIONS BY MR. CASS: 522 MR. CASS: Thank you, sir. I think that means that things swing back to me for the year-end issue. 523 Just before I come to that, Mr. Chair, if I might come back to the subject of undertaking responses. I know that you suggest that the company consult with Board Staff on this and the company will do that; however, for the benefit of the Board and any who may read the transcript or may be listening to this proceeding, the company has double-checked and has satisfied itself that all undertakings have been responded to. 524 J.5.1 was filed at the end of yesterday. That may be one that people were wondering about, and then of course J.10.2 and J.10.5 today. The company has been through what it believes to be the complete list of undertakings and has the dates when each was answered so can, again, go through that with Board Staff. 525 MR. BETTS: Thank you. 526 MR. CASS: I felt I should clear that up because there was some uncertainty in my mind when you put the question to me, Mr. Chair, about the status, but the company has doubled-checked. 527 Next, Mr. Chair, when I was preparing the argument on deferred taxes yesterday I prepared a brief, and I knew that a brief would be necessary. At the same time, I prepared a brief for the change of year-end issue, which I have brought with me. I don't think I will need it as much as was necessary for the purposes of the deferred taxes argument, in fact, I at most would probably refer to it just a few times. However, as long as the Board isn't concerned about the extra burden of paper that this would mean, I will pass it out to the Board and as I said, I'll probably refer to it a few times during my submissions. 528 MR. BETTS: We're not concerned about that excess paper. In most cases we find it helpful. 529 MR. CASS: And again, Mr. Chair, as in the case of the other brief, this is completely things that are from the record of this case, there is nothing new in the brief. 530 MR. SCHUCH: Mr. Chair, I think we can assign Exhibit K.13.2 to this document entitled, "Brief submitted on behalf of Enbridge Gas Distribution Inc. for argument in chief on issues 13.1 and 13.2, change of year-end." 531 EXHIBIT NO. K.13.2: DOCUMENT ENTITLED: BRIEF SUBMITTED ON BEHALF OF ENBRIDGE GAS DISTRIBUTION INC. FOR ARGUMENT IN CHIEF ON ISSUES 13.1 AND 13.2, CHANGE OF YEAR-END 532 MR. BETTS: Thank you, Mr. Schuch. 533 MR. CASS: Mr. Chair, at the risk of unduly lengthening things, because I don't intend to actually go to every document in this brief, perhaps I should just for the record indicate what is in it and confirm by doing that my statement that these are already things filed in this case. 534 So at tab 1 is the company's application, the exhibit number of this in this case is shown in the upper right-hand corner. At tab 2 is the extract from the settlement proposal dealing with change in year-end issues and again, the appropriate exhibit number shown in the upper right-hand corner. 535 I've included a number of transcript references at tabs 4, 5 -- I'm sorry, tabs 3, 4, and 5. Many of the transcript references that I will provide during my submissions can be found here, but I will not each time go and turn up the appropriate place, I'll give the Board the paragraph number. I think it would just take too long for us to search each time for the appropriate reference. 536 Then finally, I've included at tabs 6 and 7 extracts and again, these are extracts only from the two Connecticut decisions that were filed respectively as Exhibits J.10.8 and J.10.7. 537 MR. BETTS: Thank you. 538 MR. CASS: Now, Mr. Chair, before I embark on my submissions with respect to this change of year-end issue, I feel a need to express to the Board the fact that the company is faced with something of a dilemma in making its submissions on this point. 539 On the one hand, and to be very blunt, Mr. Chair, the company believes that the intervenor theory that the Board has heard about regarding a so-called overearnings adjustment is utterly without merit. That would suggest that perhaps the theory should get only a cursory treatment by me in argument and should not even be dignified with lengthy submissions. That's the one side of the dilemma. 540 The other side of the dilemma, Mr. Chair, is as the Board is aware, the price tag that intervenors are attaching to this theory is in the order of $30 million, that's a lot of money by anybody's standards. That is something that although the company may believe that the theory deserves no more than cursory treatment, really puts a responsibility on the company to be sure that it has plainly and fully expressed to the Board it's concerns about this theory. And there's also the fact that, in the company's view, there are really a great number of points that can be brought forward to show why this theory is wrong. 541 So really, the resolution of the dilemma that I've described, Mr. Chair, is that in the end, the company feels a responsibility to make sure that it does provide a thorough argument on this point and does bring across to the Board all the reasons why it believes that the theory is wrong, although, again, because of the company's view that this is without merit one might have expected, perhaps, a much more cursory treatment of it. 542 I just wanted to say that by way of introduction into submissions that are perhaps relatively speaking a little more lengthy than might otherwise have been the case. 543 To begin with, Mr. Chair, I think it's important for the purposes of argument in chief to lay out what the company proposed to the Board. I will try to go through this quickly but there is a little bit of detail to it. 544 As the Board is aware and has heard, I think, a number of times already in connection with the year-end issue, what the company applied for in its application which I included in K.13.2, was rates to be set on a cost-of-service basis for a 12-month test year. This 12-month test year covered the period from October 1 of this year, 2004, to September 30th of 2005. 545 In the same application, the company proposed to change its fiscal year to accord with the calendar year. That can be seen at paragraph 4 of the application at tab 1 of K.13.2. What this meant, though, was that there was a -- what's been referred to as a stub period left over. The proposal to change the year-end would mean that the next test year this Board would deal with was January 1, 2006, to December 31, 2006, the 12-month test period up to September 30th, 2005, combined with that new fiscal year left a stub period from October 1, 2005 to January 1, 2006. 546 As the company stated in its evidence, there is no approved methodology that the company is aware of for a 15-month cost-of-service presentation and for that reason the company does not and did not have the information need to make a cost-of-service application to set rates over a 12-month period. 547 The company's evidence in that regard is at Volume 10 of the transcript, paragraph 71 to 76. 548 While the company was not able to make a 15-month cost-of-service application, what it was able to do was deal with the stub period by endeavouring to propose a reasonable proxy for cost of service over that three-month period. The company therefore proposed, in connection with the three-month stub period, what it believed to be a reasonable proxy and that was an indexing mechanism, as the Board is aware, based on 90 percent of the consumer price index. 549 Again, as appears from paragraph 4 of the application, what the company proposes is that this indexing mechanism be applied to the Board-approved fiscal 2005 distribution revenues prorated for the stub period. The increase in forecast revenue at existing rates resulting from the application of this proposed mechanism has been indicated in evidence to be approximately $4.5 million. The reference for that is Exhibit A9, tab 1, schedule 3, page 5, paragraph 16. 550 The company's evidence went on to address the cost increases that justify the application of this indexing mechanism for the stub period. That's at Exhibit A9, tab 1, schedule 2. Without turning it up, this evidence discussions the impact of inflationary pressures, customer growth and some particular items like the increasing cost of employee benefits. And then some further information including a breakdown of the cost pressures with dollar amounts was provided in response to VECC IR No. 136 that's Exhibit I, tab 18, schedule 136. 551 Going one step further, in order to test the reasonableness of the indexing mechanism, what the company did was it compared the revenue requirement for a 2005 test year with a December 31st year-end using January 2004 rates to the revenue requirement for the same test year with adjusted rates. The explanation behind that, the narrative, is at Exhibit A9, tab 1, schedule 3, and then there's numerical data provided in schedules 3B and C of the same reference. 552 Without getting into how it was done and the narrative behind it, which the Board can find, this comparison showed that the company would require an increase in rates of $4 million for the stub period. That can be found at Exhibit A9, tab 1, schedule 3, page 4, paragraph 13. 553 So in the company's submission, as well as the evidence about the impact of inflationary pressures, customer growth, and so on, the particular evidence I've just referred to supports the reasonableness of the proposed indexing mechanism. 554 Now, also, I think just to be sure, for the purposes of argument in chief, that the company's proposal is laid out for the Board in full, I think I need to address some of the spin-off issues that arise from the existence of the three-month stub period. And again, I'll try to go through it fairly quickly because it's really just ensuring that the company's proposal is properly and fully presented to the Board. 555 Mr. O'Leary has already addressed the proposal for demand-side management in relation to the stub period and also for transactional services during that period; however, there are some other transitional issues, if I can use that terminology. 556 Other such issues discussed during the hearing related to deferral and variance accounts and the PGVA, as well as the phase-in of the rate impacts of upstream cost allocation changes dealt with under issue 15.4 of the settlement proposal. So I'll quickly run through these again just to present in full the company's proposal for the stub period. 557 As far as deferral and variance accounts are concerned, the company proposes to clear such accounts as the Board deems appropriate as of October 1, 2005 - this is, of course, in the event of a Board approval of the year-end change - based on balances projected as of July 31st, 2005. The reference for this is volume 10 of the transcript, paragraph 201. 558 The company also suggests that any variances from the projected balances in the October to December period would be reviewed in a future filing by the company, whether that's a QRAM filing or some other filing. 559 Now, turning to the PGVA, and again, in the event that the change in year-end was approved, the company's proposal is that it would clear the PGVA for the 12-month period to September 30th, 2005, and then for the three-month stub period, would evaluate the variance relative to what was forecast and, if material, clear that variance at the end of three months. That's at volume 10 of the transcript, paragraph 204. 560 The other transitional issue that I referred to in the event that the year-end change goes ahead concerns the phase-in under issue 15.4 of the settlement proposal. The Board will recall, I think, that Ms. Giridhar addressed this in some detail during her testimony. I think the Board will remember Ms. Giridhar's discussion of a balancing between additional administrative efforts on the one hand and fairness to the customers -- the customer classes on the other hand. 561 If the phase-in proceeds October 1st of each year but the year-end is changed to January 1st, Ms. Giridhar indicated that there are additional adjustments that would have to be made. That's at volume 10 of the transcript, paragraph 206. 562 Fairness to the customer classes suggests that the phase-in should proceed on October 1st and that is what the company proposes for the first two years. Ms. Giridhar explained that the reason for that is that in the first two years, approximately 80 percent of the benefits of the phase-in are passed on, so that's the period when fairness is most heavily weighted opposite the additional administrative work in the balancing that she described. That was at volume 11 of the transcript, paragraph 519. However, Ms. Giridhar did suggest that after the two years, when 80 percent of the benefits have been passed on, that at that point, by year 3, perhaps, the additional administrative work is a consideration that would then outweigh fairness. 563 So the company's proposal is that this phase-in be effective October 1st for the first two years, but it would have no objection if the Board were to decide that for the third year, the phase-in should proceed as of January 1st. That would be, actually, January 1st of 2007. The reference for that is volume 11 of the transcript, paragraph 521. 564 So that, I think, sums up the company's proposals in respect of the year-end change, and unless there's any uncertainty about that, I will then move on to some submissions about the issue that has taken up more time here, that being the intervenor theory under issue 13.1 of this case. 565 MR. BETTS: Please proceed. There may be some questions that pop up as you go. 566 MR. CASS: Thank you, sir. 567 To begin with, I make the observation that in respect of the year-end issue at large, there is no settlement at all in this case, and I again included excerpts from the settlement proposal at tab 2 of Exhibit K.13.2. I don't think we need to turn it up. But it is clear, I believe, that even aside from the issue about the so-called overearnings adjustment proposed by some intervenors, there's no agreement even on the issue about the change in year-end of the company. 568 What some intervenors have presented under issue 13.1 is not a position in respect of the basic year-end change but this theory that the year-end change - and I'm quoting from the settlement proposal here - "must be accompanied by an equity overearnings adjustment." 569 I emphasize at this point, Mr. Chair, what I hope has become clear as this issue has progressed through this hearing. The proposal by the intervenors for this so-called overearnings adjustment is most certainly not what the company applied for. In the company's submission, intervenors have advanced a proposal that is materially different from what was requested. In fact, I would say that words "materially different" may be not sufficient to capture the vast difference between what the company believes that it applied for and what intervenors are proposing. 570 As I indicated when I was addressing the company's proposal, the company requested what it believes to be a modest increase in rates for the stub period that is just and reasonable due to the cost pressures that I've already described and are explained in the evidence. Not only does the intervenor proposal mean that there would be no such modest increase in rates, it means that the company would be paying $30 million to ratepayers in the form of reduced rates by reason of the change of year-end. 571 The company's position, and I hope there's never been any uncertainty in the Board's mind about this, is quite simply that it does not wish to pay a price of $30 million for a change of year-end. The company does not believe that any price, based on the theory espoused by some intervenors, should be paid for a change in year-end. 572 So in the testimony of Ms. Hare, what the company did was it advised the Board that if there is to be any so-called overearnings adjustment as proposed by some intervenors, it does not wish to proceed with the change of year-end. 573 I think it's important to make clear that the company does stand by what it applied for, that being a change in year-end with an indexing mechanism. The company is not seeking to change or withdraw its application; however, the company does not want something materially different from what it applied for, that being a change of year-end with a $30 million price tag. 574 The other thing that, in my submission, is important to bear in mind when considering the portion of some intervenors on this issue is that the $30 million only comes into issue if there is a change of year-end which gives rise to this so-called stub period. So if the suggestion by some intervenors is that it's not open to the company to decline the change of year-end with a $30 million price tag, then what's essentially being said to the Board is the Board should somehow force the company to change its year-end to create this $30 million so-called overearnings adjustment. So I think it's quite important to recognize that there are two different things potentially happening with this position coming from some intervenors. First, there's the claim for $30 million which the company believes is completely wrong in principle. 575 Second, there's this apparent effort to turn this $30 million into almost some sort of almost entitlement that would occur by a Board decision which somehow prevents the company from not proceeding with the year-end change. I know that's a double negative but it was intentional. Not only is there this $30 million claim, but there's this suggestion that somehow the company would be prevented from not making the change to ensure that the $30 million is there as some intervenors think that it should be. 576 This, again, is essentially suggesting that the Board sought to force the company to change its year-end to create this so-called $30 million overearnings adjustment. 577 In my submission, intervenors have at no time in this case put forward any basis upon which the company should be forced to change its year-end and have offered no evidence providing a factual foundation for such an unprecedented, in my submission, requirement. 578 So in my submission, this brings us back to what Ms. Hare stated in her evidence at Volume 11 of the transcript, paragraph 418, the company's view is that if for any reason the Board does decide that there's a $30 million price tag attached to the change in year-end, or any price tag based on the intervenor theory, then in the company's submission, it would be appropriate for the Board to leave it to the company whether it wishes to proceed with the change in year-end given the conditions determined to be appropriate by the Board. 579 This, then, brings me to submissions on the intervenor theory itself and in order to address that, I'd like to start with some propositions which I think are basic and clear propositions that bear on this subject. The first proposition is this: That return on equity or ROE is virtually by definition an annual value. So while there might be some sort of circumstances where a business would have reason to calculate an ROE for a different period such as a quarter, the calculated number really only has meaning when viewed within a full annual cycle. Just to use a simple example, if any business were to report that in its previous quarter it earned an ROE of 5 percent, in my submission, that information would not be meaningful to anyone assessing that business unless presented in an annual context. 580 This also is where the Connecticut cases referred to by Ms. Hare are of some interest. The Connecticut cases were referred to by the company's witnesses because they show that return is calculated on an annual basis even when it is some shorter period than a year that triggers the need to calculate the return. As I said, extracts from these cases are included at tabs 6 and 7 of Exhibit K.13.2 and I don't want to spend a lot of time on them. The Board, of course, can look at the cases itself but I did want to bring out just a few points from the extracts that are in K.13.2. 581 Looking first at tab 6, the decision in the Connecticut Light and Power case that was filed as Exhibit J.10.8. And again, I'm not going to spend a great deal of time on it, but at the bottom of page 2 of the decision at tab 6, one can see how the issue about the possibility of overearnings came into play in this case. 582 At the bottom of page 2, there is an extract from the governing statutes of Connecticut and the opening words of this statute make clear why the issue arose. The opening words indicate: 583 "That the department shall hold a special public hearing on the need for an interim rate decrease, one, when a public service company has for six consecutive months earned a return on equity which exceeds the return authorized by the department by at least one percentage point." 584 So the governing statute of this particular utility requires that a certain hearing be held when return on equity has exceeded the authorized amount for six consecutive months. This obviously is in the context of a time period other than a year; however, if one looks further at the case, and I've only included extracts, I think it is apparent in many parts of the case, one sees that under this statute, the Board always looks at the ROE on an annual basis. 585 So, for example, in the middle of page 3, there's a reference to the company having filed by letter -- provided the department with its order No. 1, filing for the 12 months ended September 30th, 2000, which indicated a return on equity. And the same is true every time the return on equity is referred to. It's always a 12-month period so it goes on to say: 586 "This had been preceded by an ROE of a certain percentage for the 12 months ended June 30th. The company therefore triggered the statutory requirements." 587 And there are numerous references, I won't go through them all. I think there's also just a summary of it in the findings of fact at the end of the decision, so that's page 28, No. 3 of the findings of fact: 588 "Connecticut Light and Power had ROEs of certain percentages for the 12-month periods ended June 30th, 2000 and September 30th, 2000 respectively. ROE increased to a certain amount for the 12 months ended December 31, 2000." 589 So here, even in the context where the event triggering the need to look at ROE is something less than an annual period, it's six consecutive months, consistently and without exception, the ROE is looked at and calculated on a 12-month basis. 590 The Yankee Gas case is similar, it's at tab 7 of Exhibit 13.2 and I'll just briefly refer to it. Looking at page 1 of the decision, it's not actually numbered, but it appears here behind the face page and it has the word "decision" at the top of it. One can see under the background section that Yankee Gas requested approval from the Department of Public Utility Control to file it's annual report for a year ending on December 31st rather than September 30th. 591 There was a second proposal by Yankee Gas in this case, and that was to change to quarterly rather than monthly reporting to the department. 592 Looking at page 2 of the decision, one can see that actually the reason why Yankee was proposing to change its year-end was, in fact, because it was a subsidiary of Northeast Utilities, referred to here as NU, which was a publicly-traded company and kept its financial statements on a calendar year-end basis. 593 That's in the big paragraph in the middle of page 2 of this decision. 594 What happened in the end result was first, the regulator approved the change of year-end. That can be seen in the conclusion at page 8 that I've included in this brief. And also, because of Yankee's request to change from monthly to quarterly reporting, the department addressed how returns are calculated. So one can see this on page 3. 595 At the top of page 3, there's the reference to the change in monthly financial reporting to quarterly reporting, and in the last full paragraph on that page, it's indicated that the Office of the Consumer Council put in written objections which proposed the change to quarterly filings, stating that such a change would make it more difficult for the department to determine whether the overearnings measure under the statute that we looked at in the previous case had been triggered. The department didn't accept that argument. The department disagreed with the Office of Consumer Council in that the end of each calendar quarter will be calculated using a 12-month rolling average as is now done. 596 So again, whether it's quarterly reporting, whether it's monthly reporting, when the time period triggering a calculation of return was less than a year, it was a rolling 12-month approach that was used to calculate the return. 597 As it happened, because there was both a change in year-end proposed in this case and also an issue about how to measure so-called overearnings, this tribunal considered measurement of overearnings in the context of a year-end change, yet there is no suggestion anywhere in this decision that the overearnings issue would mean looking at a three-month period on its own and attributing an average return to that three-month period. 598 So that's a somewhat lengthy explanation in support of the first basic proposition that I was advancing to the Board on this branch of the argument. 599 My second proposition is that it's particularly true in the case of a seasonal business that an ROE, in order to be meaningful, must be calculated on an annual basis. And I think I can just illustrate that with a simple proposition. In my submission, it would be misleading and deceptive for a company with a seasonal business to present its ROE by annualizing just one quarter, such as its strongest quarter. That would be quite a distortion of the results of a seasonal business. So it's particularly true in the case of a seasonal business that ROE be looked at on an annual basis. 600 Third, it's axiomatic, I submit, that in the case of a business with seasonal results, better returns are going to be achieved in some parts of the year than others. What this means is that superimposing an average return, that is, one-fourth of the annual return, on a quarter of a business with seasonal results is going to automatically create a distortion. This is so simply because the seasonal business does not earn one-fourth of its annual return in each quarter. 601 And then that fourth and final basic proposition that I wish to submit to the Board is that the seasonality of a business like that of Enbridge Gas Distribution is a function of weather, it is not in any way a function of the choice of fiscal year or measurement period that is made for that company. The seasonality doesn't go away and it doesn't change when the company proposes to change its year-end. 602 So for these reasons, to say that a change in year-end justifies treating a seasonal quarter as an average quarter is simply wrong, in principle. The weather won't change and the seasonality will not change regardless of the date chosen for a year-end. 603 As I think was observed -- may have been observed in the evidence -- I don't recall for sure, but in any event, in the case of Enbridge Gas Distribution, if the company were not proposing to change its year-end, in my submission, no one would be disputing the fact that the utility will earn more in the period of October to December 2005 than in its spring and summer quarters. 604 Ms. Hare testified at volume 10 of the transcript, paragraph 76, that the suggestion that because of the year-end, the company should pay these so-called overearnings to ratepayers means a confiscation of earnings that the company would achieve with or without a change in year-end. A similar point is that the rates determined by the Board to be just and reasonable for the 12-month test year ending September 30th, 2005 do not overnight become unjust and reasonable for no reason other than a change in fiscal year-end. 605 To put this in perhaps an even more narrow context, the intervenor theory, if it's correct, would mean that rates as of 11:59 p.m. on September 30th, 2005 are just and reasonable, and at 12:01 a.m. on October 1st, 2005 would become unjust and reasonable, even if absolutely nothing else changed except for the fact that the company is changing its year-end. In my submission, that simply can't be right. 606 I'd like to move on to some submissions as to why that is not correct. What intervenors are really asking the Board to do, in my submission, is pretend that when this year-end is changed, that somehow seasonality will change as well such that the stub period can be treated as an average quarter when we all know that it's not an average quarter. 607 The flaw in this argument is that it focuses on points or periods of measurement while failing to take into account the fundamental point which is the seasonality of the company's business. In order to discuss this in a little more detail, it will assist me if I can just use some terminology. 608 What I'd like to do is refer to the quarters from October to December and January to March as strong quarters. I'm using that only in a relative sense. But relative to the other two quarters, those are the company's strong quarters and the other two are relatively weak. 609 The differing results between the strong quarters and the weak quarters are a reflection of weather, and more specifically, the obvious fact that in our climate, we have four seasons. Another obvious fact is that these four seasons are going to remain more or less constant regardless of the time periods and points in time that one might want to choose, whether it's for measuring, recording, reporting, or analyzing results. No matter what time periods or points in time one wants to choose, the company is still going to have two strong seasons and two weak seasons in every 12-month period. 610 What the intervenors, or some intervenors suggest that the Board ought to do is, for that stub period, artificially suppress what the company would return -- earn on a seasonal basis in that quarter down to an average return. In my submission, what this is really doing, or what this would do is upset the seasonal balance of the company's results. 611 To put it even more plainly if I can, on a seasonal basis, the company's two strong quarters are balanced against two weak quarters. But if what one does is take one of those stronger quarters and reduce it down to an average quarter without any corresponding adjustment to three companion quarters, it's disrupting the seasonal balance. 612 In order to maintain the seasonal balance, if one quarter is to be restricted to one-fourth of the Board ROE, then the return for three companion quarters, either in front of or after that quarter, has to also be brought to an average amount, that being three-fourths of the annual return, to keep the seasonal balance. Otherwise, the balance is lost by artificially adjusting downwards one of the strong quarters without any corresponding adjustment to the other quarters that combine to provide the seasonal balance. 613 Now, Ms. Giridhar addressed this in a similar fashion in her testimony. She explained that to bring back the seasonal balance under what intervenors are proposing, or some intervenors, is that rates would have to go down in the other high-volume quarter and up in the two low-volume quarters; or alternatively, that the company would have to change its rate-setting process to recover all its fixed costs from fixed charges. This was, among other places, at Volume 10 of the transcript, paragraph 170. 614 But even just in the case of rate 1 customers as Ms. Giridhar pointed out, this notion of recovering all fixed costs from fixed charges is not a realistic one because the proposal to increase the charge just from $10 a month to $11 and something a month has met with real resistance in this case and recovering all fixed costs from fixed charges would require just for rate 1 customers an increase to $33 per month. 615 So as Ms. Giridhar pointed out, for the rate structure to earn the same return every quarter requires either rate instability from quarter to quarter or full recovery of fixed costs from fixed charges which means a threefold increase in fixed charges for residential customers. That's at Volume 10 of the transcript, paragraphs 1246 to -8 and at Volume 11 of the transcript paragraph 179. 616 So taking just one strong quarter and artificially suppressing it to make it into an average quarter without converting three companion quarters improperly skews the seasonal balance of the company's business. This in effect gives rise to the hit, if I can use that loose word, to retained earnings that Mr. Ross described in his evidence and would continue into eternity, I think were his words, if that approach were taken because it has thrown off the seasonal balance. 617 Also, if this intervenor theory is correct, it means that there would be very significant differences in rates depending on the test period that a utility chose to apply for even though all other factors remained exactly equal. And I can give some examples. Take the example of a utility with a December 31st year-end. Such a utility could take advantage of this theory and apply for rates over a nine-month test period to September 30th of the following year. This nine-month test period would combine two so-called weak quarters with one strong quarter, so applying this approach of average returns would mean the two weak quarters would have to have increased returns effectively to return one fourth of the annual ROE and rates would increase and create a windfall for the utility. 618 The same would be true if that utility chose to apply on the basis of a 21-month test period. The converse is if that same utility were to apply for rates over a 15-month test period there would be three strong quarters, two weak quarters, the reverse would happen, suppressing returns in the strong quarters to an average return would decrease rates and create a windfall for the ratepayers. 619 One can go on with these examples, but what they are showing is that even assuming that all underlying costs and revenues stayed exactly the same, the mere choice of the time period results in a windfall for either the shareholder or the ratepayer if the intervenors' theory is applied. In my submission, this just can't be correct, and as Ms. Giridhar said her evidence at Volume 10, paragraph 165, as long as there is no change to the underlying cost in revenue elements, rates established under cost-of-service regulation should be good for the future. It shouldn't turn on the amount of time that they're going to be in existence for if the underlying elements are taken to be exactly the same and unchanged. 620 Another example of why this intervenor theory leads to incorrect results is the Union Gas change of year-end that Ms. Hare testified about in her evidence. As she explained, if the intervenor theory were correct, it would mean that when Union Gas changed its year-end, there would have been a significant increase in rates simply by reason of the year-end change. This is so because the so-called stub period in the Union Gas situation included two of the relatively weak quarters. So the effect of -- and superimposing this average approach to quarterly returns on the seasonal business in the case of Union would have been that a windfall, similar to that which certain intervenors are seeking in this case, would have been realized by Union's shareholder in that other situation. The transcript reference for this is Volume 10 of the transcript, paragraph 81. 621 Now, there's yet another element to all of this which was addressed by Ms. Giridhar in her evidence but intervenors, in my submission, are just conveniently choosing -- I shouldn't say conveniently -- are simply overlooking, for whatever reason. Ms. Giridhar pointed out very plainly in her evidence that in the so-called shoulder period of October to December, which is the stub period we're now talking about, there is significantly higher usage by large-volume customers than in the January to March winter period. She pointed out that if one were to take this three-month approach on the basis advocated by some intervenors, then one would determine pipeline usage in that stub period on its own by the different rate classes and one would find that the large usage by high-volume customers in this period would result in a cost shift to these customers. This is all discussed at Volume 10 of the transcript, paragraph 175. 622 That element of the intervenor theory about looking at the stub period in the way that has been proposed is not something that intervenors have addressed in any fashion; however, in my submission, it's a very important factor for the Board to take into account that there would be this cost shift between customer classes occurring. 623 So in the end result, Mr. Chair, my submission is that the Board is left with a significant amount of company evidence on the intervenor position in respect of issue 13.1 that drive it in the direction of one conclusion and one conclusion only, and that is that the theory does not stand up to scrutiny. 624 What I would like to do, and again, I've tried to include as many of the evidentiary references as possible in Exhibit K.13.2, I'd like to, without going to each evidentiary reference, just summarize the extensive evidence that has been presented on the record in this case to refute the theory that I've been discussing. 625 The first point is this, the proposed change in year-end would have no affect on ratepayers in that they would not pay any more or less by reason of the change. The proposed change in year-end would not affect the company's profitability, nor would it change the company's retained earnings. That's evidence at Volume 10 of the transcript, paragraph 96. 626 The company does not have any different earnings or return on equity from changing its year-end, the only difference is the fiscal year is the stub period is reported. That's Volume 10, transcript paragraph 150. 627 It is purely a change in the measurement date. Volume 10, paragraph 63. 628 The second point is as follows: And again, this is all straight from the evidence and in my submission uncontradicted evidence in this proceeding. The second point is there are few phases to the company's rate process. Both phases span a 12-month operating cycle. In the first phase the company equates forecast costs and revenues over a 12-month period to determine what rate increase or decrease if any is necessary for revenues to equate with costs. That's at Volume 10 of the transcript, paragraph 161. 629 To equate costs and revenues over a three-month period is something that the Board has never approved and the company's shareholder has never received. That's Volume 11 of the transcript, paragraph 160. 630 In the second phase of this rate process, the company allocates costs at the rate class level and this is done on the basis of allocation factors which are developed using the same 12-month operating cycle. That's Volume 10 of the transcript, paragraph 163. 631 This brings me to the third point. The company's rates are designed so that it will earn its fair return over the operating cycle of 12 months. The operating cycle is always 12 months, it is never three months. If you want to test for a subset of a year which is one-quarter, you always need to look at that in the context of three other quarters. That's Volume 11 of the transcript, paragraphs 167 to 168. 632 And if I may digress at this point, really in support of my submission that these propositions are uncontradicted on the record in this case, in my submission, Mr. Fournier's evidence actually seemed to agree with the proposition that I've just put to the Board. This can be found at tab 5 of Exhibit K.13.2. This is volume 9 of the transcript and it's an excerpt from the cross-examination of Mr. Fournier. 633 So at paragraph 921, again, this is at tab 5, one can see that I put to Mr. Fournier a question about this so-called $30 million adjustment. And skipping through his answer, he indicated that he had instructed Mr. Thompson and he had run by his Enbridge committee chairman that the company is awarded or is allowed to earn a rate of return on equity which this Board sets, and how it earns that over the period of 12 months of the year is really irrelevant as long as, on average, the recovery it has over a 12-month period is the allowed return on equity. 634 In my submission, Mr. Chair, this does not in any way contradict the company's position, this agrees with the company's position. There seems to be an effort by some intervenors to impose on a three-month period of the year an average ROE. Mr. Fournier is saying that within the 12 months of the year, it's irrelevant what return is earned by the company. He's not agreeing with that effort to impose on three months an average return. 635 The company's position is that rates should be set so that over the 12-month operating cycle, that's the period over which the allowed return is earned. And in my submission, that's what Mr. Fournier says. He says that as long as, on average, the recovery it has over a 12-month period is the allowed return on equity. 636 Well, in my submission, Mr. Chair, if one were to artificially suppress the return in the stub period to the average return, unless there would be adjustments to three companion quarters on either side of it, Mr. Fournier's test would not be met; the company would not meet its average return over a 12-month period. So in my submission, Mr. Fournier has essentially agreed with the company's position about how a fair return should be looked at over the operating cycle of 12 months. 637 The next point, the fourth point that appears clearly from the evidence that the Board has in this case is that, under the Board's monitoring requirements, financial reporting is required on a 12-month basis. When the Board requests first-quarter results, what is presented to the Board is three months actual and nine months projected to give an annual ROE. The reference for that is volume 10 of the transcript, paragraph 84. 638 The fifth point that is clearly stated in the evidence is that in the QRAM process, when gas costs are adjusted for one quarter, the principle, again, is that costs and revenues and rates can only be determined on a 12-month basis. What the company does is forecast the change in costs for a 12-month period, going forward, which is essentially a rolling 12-month period, in order to determine what rates need changing. This use of the 12-month process is done with the full knowledge that rates are likely to change the very next quarter. This is all taken from volume 10 of the transcript, paragraph 166. 639 The sixth point, again, straight from the company's evidence, is that the company's approach to the stub period mimics the QRAM process by taking into account a rolling 12-month period when setting rates for the three-month period. That's volume 10 of the transcript, paragraph 181. 640 The seventh essential proposition in the company's evidence is this: The theoretical construct upon which the companies are based is that rates, once set, should be good for the future unless there is a change in economic conditions, that is, costs or revenues giving rise to a need for an adjustment. If history repeated itself, it should not be necessary to adjust the rates. That's volume 10 of the transcript, paragraph 165. 641 The eighth proposition from the company's evidence is a reduction in rates in accordance with the intervenors' position would almost certainly result in rates which would produce a significant deficiency when applied on a 12-month fiscal year and likely would require a significant increase of rates as of January 2006. That's from volume 10 of the transcript, paragraph 156. 642 In other words, if rates were to be reduced as some intervenors claim that they should be, then at the start of the next fiscal period, everything else being equal, rates would not produce sufficient revenue to allow the company to earn the Board-approved ROE and there would have to be a rate increase. Volume 11 of the transcript, paragraphs 132 to 137. 643 This indicates that the rate decrease was wrong in the first place, because as long as the company's cycle repeats itself, there should not be any need for a change in rates. Volume 11 of the transcript, paragraph 148. 644 The ninth proposition from the company's evidence: If the Board were to set rates on the basis of an ROE for the stub period that is one-fourth of the annual ROE, the company would suffer a loss to its retained earnings that would never be recovered. This is the evidence of Mr. Ross that I've already referred to. It's at volume 10 of the transcript, paragraphs 119 to 125, and it's at Exhibit K.10.3. 645 The tenth proposition from the evidence is the following: Even with that increase in rates that would have to occur at the start of the next fiscal period so that the company would be able to earn the Board-approved ROE over a 12-month test period, the loss in retained earnings in the preceding period that Mr. Ross described, that continues in eternity notwithstanding the increase just to be sure that a further loss to retained earnings doesn't occur when the decreased rates are used for a 12-month period. That's at volume 11 of the transcript, paragraph 132, and it can be seen also from looking at Exhibit K.10.3. 646 Without going into great detail, one can see from Exhibit K.10.3 that in order to get the company after the so-called stub period back to earning what was its Board-approved return on a four-month basis, it was necessary to get the revenues back up again. You will recall the witnesses talking about that. And to get the revenues back up required the rate increase at the start of that next fiscal period that I've referred to. Nevertheless, on Exhibit K.10.3, the $20 million reduction in retained earnings carries on throughout even with that increase just to be sure that there's no reduction in the future period. That can all be seen on Exhibit K.10.3. 647 And then the eleventh and final proposition that, in my submission, is clear from the company's evidence is that taking one-fourth of an annual ROE for a three-month period is a completely different issue from the rate-indexing mechanism that was requested by the company in its application and has no precedence. That's at volume 11 of the transcript, paragraph 170. 648 Again, in my submission, this is uncontradicted, because when Mr. Fournier testified, he indicated that he has considerable experience in the regulatory area in Canada and he was unable to cite any instance where an energy regulator has set ROE for a 15-month or a three-month period. That's at volume 9 of the transcript, paragraphs 940 to 945. 649 So again, Mr. Chair, I apologize for taking such a lengthy period of time to address what, in the company's submission, is an intervenor theory that is completely wrong in principle from the start, but the need that the company felt was to express to the Board just how many elements of the evidence in this case completely knock the underpinnings out from under that theory. I've given these 11 propositions from the evidence, and I've also attempted to explain just in principle why the theory is wrong. 650 So to recapitulate, if I may, the intervenors' claim is wrong in principle because it artificially assumes that a strong quarter of the company's business should, on its own, be treated for ROE purposes as only an average quarter. This upsets the seasonal balance of the company's results. It causes the reduction in shareholders' retained earnings that Mr. Ross described, and this is a reduction which, in the absence of some counterbalancing adjustment to companion quarters, would never be recovered by the company and would therefore result as an unwarranted hit, if I can use that word, to the company's shareholder. 651 And again, I apologize for the length, but that completes my submission on this issue. 652 MR. BETTS: Mr. Cass, I did have a couple of questions but I'm going to take you back to the application, if I can. I wanted to -- and put your mind on this one if you will, focus for a moment on the use of the CPI as an escalator. 653 First of all, in your recent submissions, you've indicated, I think it was in proposal or proposition number seven that -- I think it was Ms. Giridhar that indicated that unless there is an apparent change to the underlying elements of cost and/or volume and/or revenue, that there need not be a change in rates. Can you point to me somewhere in the evidence that would support the need for the escalation costs? 654 MR. CASS: Yes, that was the evidence that I referred to at the beginning of my submissions, Mr. Chair. I don't know whether you want to turn it up right now, but I'll give you the references. Exhibit A9, tab 1, schedule 2, if I have the right reference, addresses the cost increases that justify or support the application of the indexing mechanism and also VECC IR No. 136. 655 That was A9, tab 1? 656 MR. CASS: A9, tab 1, schedule 2. I don't want to take up a lot of time on the record, but you'll see that this evidence talks about what sort of customer growth is expected in the three-month stub period, that's in paragraph 3. There is discussion in paragraph 5 about what's expected by way of capital expenditures. In paragraph 6, there's discussion about what's expected by way of O&M. So this is the company's presentation about the underlying changes that it anticipates for the stub period that would justify the application of an indexing mechanism. 657 MR. BETTS: Thank you, Mr. Cass. Another question. When the use of the CPI first came up for 2003, there was some historic statistical analysis that supported a trend in the CPI that in many ways paralleled the company's costs or, in fact, in that case I think it related to the company's rates rather than the company's costs. Is there any evidence that supports that a similar trend exists on a quarterly basis? 658 MR. CASS: I will double-check this, Mr. Chair, but I have to say I don't think that that evidence was presented. I'll just double-check. That's correct, Mr. Chair, I have to say that that evidence is not in the record. 659 MR. BETTS: I think that concludes my questions. Mr. Sommerville. 660 MR. SOMMERVILLE: I have none, thank you. 661 MR. BETTS: The Board Panel has no further questions. Are there -- I would say, then, at this point, we've concluded the company's argument in chief, thank you very much, it was very extensive and that will help us and the intervenors to move forward. 662 I suppose at this point, Ms. Lea, is there a point that can assist the Board at this stage? 663 MS. LEA: I was wanting to speak very briefly to a scheduling matter. 664 MR. BETTS: That can assist the Board. 665 MS. LEA: Thank you. I'm not sure if you had an opportunity to receive my message that we had a request from Mr. Klippenstein who's due to argue on Monday that he file written argument. He's been called before another court so he's requesting then to not be on the schedule for oral argument on Monday. He was listed as second following Ms. Street, and to file written argument. And I should get back to him this afternoon. And in addition I wanted, if the Board accepts this request of Mr. Klippenstein, I wanted to put it on the record so that parties who may be following the transcript can understand what's going on on Monday. 666 MR. BETTS: Thank you. And the Board Panel actually has considered that request and certainly, we've -- I think we've already extended that flexibility to some other intervenors and would be prepared to do it for Mr. Klippenstein as well. 667 I believe the message I received indicated that he was unsure that he could appear on the 13th. 668 MS. LEA: My understanding is that he believes he cannot appear. He thinks that is his commitment elsewhere will last that week. 669 MR. BETTS: Well, then the Board Panel is prepared to say, if he cannot appear on the 13th, because his appearance on the 13th would be our preference, that we would be prepared to receive written arguments on the same schedule as the other two intervenors. 670 MS. LEA: Thank you very much. So that then would leave us beginning on Monday at 11:00 a.m. with two intervenors listed for argument. 671 MR. BETTS: Right. Okay. Thank you and that is on the record so we will see the parties at 11:00 a.m. on Monday morning. Thank you all. We'll adjourn now. 672 --- Whereupon the hearing was adjourned at 3:40 p.m.