Rep: OEB Doc: 12WVY Rev: 0 ONTARIO ENERGY BOARD Volume: 4 9 OCTOBER 2003 BEFORE: P. SOMMERVILLE PRESIDING MEMBER A. BIRCHENOUGH MEMBER 1 RP-2003-0063 2 IN THE MATTER OF the Ontario Energy Board Act, 1998, S.O. 1998, c.15 (Sched. B); AND IN THE MATTER OF an Application by Union Gas Limited for an Order or Orders approving or fixing just and reasonable rates and other charges for the sale, distribution, storage, and transmission of gas for the period commencing January 1, 2004. 3 RP-2003-0063 4 9 OCTOBER 2003 5 HEARING HELD AT TORONTO, ONTARIO 6 APPEARANCES 7 PAT MORAN Board Counsel MARTIN DAVIES Board Staff JAMES WIGHTMAN Board Staff MICHAEL PENNY Union Gas Limited TOM BRETT Ontario Association of School Business Officials MICHAEL JANIGAN Vulnerable Energy Consumers' Coalition ROBERT WARREN Consumers Association of Canada ALICK RYDER City of Kitchener DWAYNE QUINN City of Kitchener GEORGE VEGH CEED, OESC, Superior Energy Management, Union Energy, TransAlta JAY SHEPHERD Ontario Public School Boards Association MIMI SINGH CME RANDY AIKEN London Property Management Association, Wholesale Gas Service Purchasers Group SCOTT STOLL Northern Cross Energy TIBOR HAYNAL TransCanada PipeLines ROBERT ROWE Enbridge Gas Distribution Inc. PETER THOMPSON Industrial Gas Users Association BRIAN DINGWALL Energy Probe, HVAC Coalition, Distributed Energy Association DERECK FRANCIS Energy Objective VALERIE YOUNG Ontario Association of Physical Plant Administrators PETER SCULLY City of Timmins, City of Sudbury, FNOM JOHN RATTRAY Ontario Power Generation 8 TABLE OF CONTENTS 9 MOTION BY TRANSALTA: [19] SUBMISSIONS BY MR. VEGH: [20] SUBMISSIONS BY MR. PENNY: [41] PRELIMINARY MATTERS: [56] UNION GAS LIMITED - PANEL 4; RESUMED; GARDINER, POREDOS, ROGERS [66] EXAMINATION BY MR. PENNY: [70] CROSS-EXAMINATION BY MR. WARREN: [81] RULING: [232] UNION GAS LIMITED - PANEL 4; RESUMED; GARDINER, POREDOS, ROGERS [249] CROSS-EXAMINATION BY MR. THOMPSON: [255] CROSS-EXAMINATION BY MR. RYDER: [671] CROSS-EXAMINATION BY MR. QUINN: [903] CROSS-EXAMINATION BY MR. RATTRAY: [980] 10 EXHIBITS 11 EXHIBIT NO. M.4.1: EXHIBIT J.31.G2.57 FROM EBRO 499 [788] EXHIBIT NO. M.4.2: DOCUMENT ENTITLED "PICKERING A AND BRUCE A UNITS RETURN TO SERVICE ASSUMPTIONS BASED ON IMO 18-MONTH OUTLOOKS" [988] EXHIBIT NO. M.4.3: VOLUME ACTUAL VERSUS FORECAST [992] EXHIBIT NO. M.4.4: REVENUE ACTUAL VERSUS FORECAST [995] EXHIBIT NO. M.4.5: ADDITIONAL REVENUE FOR EACH 100,000 10(3)m3 INCREASE IN CONTRACT VOLUME [998] 12 UNDERTAKINGS 13 UNDERTAKING NO. N.4.1: TO PROVIDE THE TOTAL S&T REVENUES FOR EACH OF THE YEARS 2000 TO 2003 [202] UNDERTAKING NO. N.4.2: TO PROVIDE A SENSITIVITY OF THE REVENUE DEFICIENCY TO A 100 10(6)m3 UNDERESTIMATE OF CONTRACT DEMAND USING TWO SCENARIOS; ASSUMING THE CDS DO NOT DECREASE OR WITH A CHANGE IN THE CONTRACT DEMAND; FURTHER, TO PERFORM SENSITIVITY ANALYSIS FOR M17 FIRM AND R25, SPECIFYING IF AVERAGE IS WEIGHTED OR NOT [578] UNDERTAKING NO. N.4.3: TO REPRODUCE FORECAST FOR THE T3 2004, NORMALIZING A PORTION OF ITS LOAD [756] UNDERTAKING NO. N.4.4: TO REPRODUCE FORECAST FOR THE T3 USING THE THREE YEARS OF 2001 TO 2003 INSTEAD OF 2000 TO 2002 [779] UNDERTAKING NO. N.4.5: TO REDO THE KITCHENER FORECAST REFLECTING A 10,000 10(3)m3 UNDER TWO SCENARIOS; ONE WITH A CONTRACT CHANGE AND ONE WITHOUT A CONTRACT CHANGE [882] UNDERTAKING NO. N.4.6: FOR UNION GAS TO PROVIDE THE AVERAGE VALUE OF RENEWAL OF THE 50 PJS, THEN EXTEND THAT TO THE 24 ADDITIONAL PJS TO BE RENEWED AND PROVIDE CALCULATION RESULT FOR THE LONG-TERM STORAGE PREMIUM FOR 2004 [974] UNDERTAKING NO. N.4.7: TO PROVIDE THE BREAKDOWN AMONGST THE RATE CLASSES M7, RATE 25, AND RATE 100 ATTRIBUTABLE TO ELECTRICITY GENERATION [1119] UNDERTAKING NO. N.4.8: TO RESTATE EXHIBIT M.4.4 WITH THE REMOVAL OF THE COMMODITY COMPONENT FOR BOTH RATE 25 INTERRUPTIBLE AND M7 FIRM [1360] 14 --- Upon commencing at 9:38 a.m. 15 MR. SOMMERVILLE: Good morning. Please be seated. 16 Good morning. I see, Mr. Vegh, you're in the front row this morning. Your application for late intervenor status on behalf of TransAlta was discussed briefly yesterday. Is that the occasion of your attendance today? 17 MR. VEGH: Yes, it is, sir. Thank you. I spoke to Mr. Penny last evening and today, and I was just going to address this morning the issue of filing of evidence, which I think is the only evidence between Union and TransAlta. 18 MR. SOMMERVILLE: I think we can then consider this your -- in effect, your motion, and you can begin, Mr. Vegh. 19 MOTION BY TRANSALTA: 20 SUBMISSIONS BY MR. VEGH: 21 MR. VEGH: Thank you. And thank you for hearing this motion on such short notice. 22 I'll be brief in my submissions. I just want to refer to a couple of things that you might have handy. The first is the notice of late intervention filed on October 7th, and second I was going to refer to the transcripts on the Coral motion of October 3rd. 23 TransAlta's interest in this proceeding and the reason for the late intervention is set out at paragraph 2 of its statement of interest, and this is just to provide some context. TransAlta operates a 575 megawatt gas-fired electrical generation facility in Sarnia, which is in Union's franchise. This facility supplies electricity both to its host and as merchant power. Just by way of background, the division between the two, 140 megawatts of the facility are physically committed to the domestic load; that's about 25 percent. The remainder, about 435 megawatts, or 75 percent, is available for merchant power. 24 What TransAlta is seeking in this application is the ability to participate as an intervenor with all the rights of an intervenor, including the right to file evidence. Now, we appreciate that this is brought late in the proceeding, and the timing of the evidence that we would propose would be the same as the condition imposed on Coral, which is to file evidence within seven days. That would be a week today, or October 16th. 25 And as I said, I understand Union does not object to TransAlta's intervention but does oppose TransAlta's request to be able to file evidence, so that's what I'll be addressing. And I'll be frank with you. I don't know right now whether TransAlta will, in fact, be filing evidence in this proceeding. This issue that I'm addressing and gives rise to TransAlta's intervention only arose on Friday, and frankly, we haven't made a decision on whether or not to file evidence. All I'm asking is that you not impose a condition that TransAlta not be able to file evidence in this case. 26 So, in other words, what we're asking for is to preserve the right to file evidence, if considered necessary. And the reason for this request comes directly out of the motion that this Board heard on Friday, brought by Coral Energy for late intervenor status and to file evidence. Coral's motion referred to two types of evidence that it proposed to file. The first type of evidence was with respect to a contractual dispute between Coral and Union, and then the second type of evidence was more generic having to do with rate design. And I'd like to just refer to the transcript where Coral described what type of evidence they want to file, and this is the type of evidence that, in my submission, has an impact on TransAlta. 27 Coral's submissions on that start at paragraph 121 where Coral talks about the unique nature of merchant gas-fired generation. The submissions read: 28 "Therefore, unlike any other high-volume customers where you tend to get high load factors and Union's current rates are geared towards that, a merchant gas-fired plant is a creature of a different nature, and you are going to have much more variability in delivery of load factor, and on average over a year a much lower load factor, may well be in the neighbourhood of 50 percent or so." 29 He then goes on to say that it's a different kettle of fish. In paragraph 123: 30 "And so it is Coral's respectful submission to the Board that now is the appropriate time for the Board to consider as an issue the design of a rate which will be tailored to a merchant gas-fired generation plant. And that is what Coral would like to file evidence on." 31 And then the Chair, Mr. Sommerville, made his findings at paragraph 241 about the type of evidence that Coral would be allowed to file -- sorry, at 240, the Board, I'm reading now, the Board stated: 32 "The Board is inclined to permit this request, and its request to file evidence is also approved, on the basis that the Board has an interest in the rate design question that the intervention raises." 33 That's rate design for merchant gas-fired generation. 34 "The Board is not interested in the contractual dispute that exists between Union and Coral Energy Canada Inc." 35 So the Board said it's not interested in the contractual dispute of interest to the two particular parties but is interested in the broader issue of designing a rate for gas-fired merchant generation. TransAlta is a gas-fired merchant generator so it obviously is impacted by any evidence of what a rate design should look like for that category of customer. So, in my submission, it would be very unusual to say that TransAlta can't file evidence on this point, and that evidence can only be filed by Coral and by Union. 36 Now, we appreciate that this proceeding is ongoing. TransAlta has, in my submission, acted in a timely manner. But the impact of Friday's decision is to effectively add a new issue to the issues list, and that issue is rate design for gas-fired merchant generation. In my submission, that has a direct impact on TransAlta and TransAlta should be allowed to file evidence on that. 37 In terms of the timing condition, I would suggest that one week would be appropriate. That would take us to October 16th. 38 Thank you. Those are my submissions. 39 MR. SOMMERVILLE: Mr. Vegh. 40 Mr. Penny. 41 SUBMISSIONS BY MR. PENNY: 42 MR. PENNY: Thank you, Mr. Chairman. 43 As I indicated yesterday, and as I advised Mr. Vegh, Union doesn't take issue with the application for intervention itself and so I'm going to restrict my submissions only to the issue of evidence. 44 In my submission, there's no reason to open this up further. What we're seeing, in effect, is a mushrooming effect from the Coral application. There is no reason for this to be coming up as a last-minute issue for TransAlta. Rate design is not a new issue. Rate design has been on the issues list from the outset. Union's rate design evidence was filed on June 30th. And so there's no reason for this to be coming up as a last-minute issue for TransAlta. 45 I would just say parenthetically, however, that the Board has, of course, considered high-load factor issues before, high-load factor customer rate classes before, but the Board has never considered end-use as a relevant consideration in rate design as TransAlta seems to want to do here. 46 But it's really a process issue more than anything else, Mr. Chairman. The fact is that we're now seeing a domino effect. The issue goes beyond just these applicants because any rate relief given to them will, of course, have a domino effect to other rate classes, or at least some other rate classes as well, and may have implications for all ratepayers. 47 So in my submission, it is not necessary and not appropriate to permit this issue to grow, in effect, and particularly at this late date, when the case is already underway, and to grow into a mini-rate design case all on its own. In my submission, there ought to be no further evidence permitted on the issue. But even if you were inclined to grant that relief, that TransAlta ought to be held to the same schedule as Coral was, not the same time limit but the same schedule, because, remember, at the end of the day, what Union has to do is respond to this stuff and do it in a way that permits us to try and stay on schedule in the case and deal with all the rate design issues when that panel comes up. 48 So it's really, as I say, a process issue more than anything else. We have no problem, in particular, with TransAlta. We just say that it's too late for these things being shoehorned into the case. Thank you. 49 MR. SOMMERVILLE: Thank you, Mr. Penny. 50 Any reply, Mr. Vegh? 51 MR. VEGH: I won't repeat what I've said. I don't disagree with Mr. Penny that this is an unusual process. But the issue is not mushrooming as a result of TransAlta's intervention, the issue is what it is and it impacts TransAlta. 52 In terms of the timing, I infer from what Mr. Penny is saying is that TransAlta should file its evidence by tomorrow, and that is not realistic. That's all I have to say in reply. 53 MR. SOMMERVILLE: The Board will reserve on this subject. We will consider the subject in the course of the morning break and hopefully we'll have a decision for the parties coming out of that break. 54 Are there any other preliminary matters? 55 MR. PENNY: Yes, Mr. Chairman. Just one or two. 56 PRELIMINARY MATTERS: 57 MR. PENNY: I wanted to -- I well, I guess there's actually three. First of all, I just wanted to let the Board know and say on the record for parties that aren't here that the document that was referred to by Dr. Weaver and marked preliminarily as Exhibit M.3.3 has been copied, and copies have been distributed and made available. 58 I wanted to also say on the record for everyone that various intervenors, in trying to comply with the Board's procedural rules, what I always call the 24-hour rule about documents that already in the record for cross-examination, parties are generally trying to comply with that. But we found recently that a number of intervenors -- I won't single anyone out in particular -- but a number of intervenors are faxing material either to my office downtown or to Mr. Reghelini in Chatham, and we're not there, we're here, so it's creating delays in getting the information. So that if parties are sending things in where the time frames are relatively short, I would ask that they -- if they can't hand them to us, which is actually -- the day before, which is the best thing to do, but if that doesn't work, that they fax them to the Union office here at Yonge and Eglinton. I'll just give the number, if I may, for the record, so that people who aren't here have it. The fax number there is, care of Union Gas, 416-482-6701. Thank you, sir. 59 Thirdly, when we actually get to resuming with the evidence with this panel, Mr. Gardiner advised me this morning that he said there's something that he said yesterday which was only partially correct, and he just wanted to make an update or a correction based on some updated evidence to something he said yesterday. So if he might be permitted to do that before we actually start with the evidence, that would about satisfactory for us. 60 MR. SOMMERVILLE: Thank you, Mr. Penny. 61 Are there any other preliminary matters before we begin the evidentiary portion of today's hearing? 62 The Board raises one and that relates to start time -- break times for tomorrow. Because of a conference call that the Board Panel, Mr. Birchenough, in particular, ought to be part of, we'd like to begin at 9:30, break at 12:30, recommence at 1:30 tomorrow. So it won't compromise our overall hearing time, but changes the morning break typically from 1:00, in that range, to a 12:30 break. If that creates any particular difficulties, please get back to us as early as possible. 63 MR. PENNY: That's certainly fine from our point of view, Mr. Chair. 64 MR. SOMMERVILLE: In that case, Mr. Penny, I guess you wanted to ask Mr. Gardiner to clarify an answer, and then, Mr. Warren, you can recommence your cross-examination. Thank you. 65 MR. WARREN: Thank you. 66 UNION GAS LIMITED - PANEL 4; RESUMED; GARDINER, POREDOS, ROGERS 67 P.GARDINER; Previously sworn. 68 S.POREDOS; Previously sworn. 69 B.ROGERS; Previously sworn. 70 EXAMINATION BY MR. PENNY: 71 MR. PENNY: Mr. Gardiner, I understand that there was a transcript reference from yesterday that you wanted to either correct or update. 72 MR. GARDINER: Yes, thank you. I have the transcripts from yesterday, and looking at paragraph 1431, where I was responding to Mr. Warren, and I mentioned $17, and both he and I were using a -- 73 MR. PENNY: Can you, first of all, explain the context of that so we can recall what it was that you were discussing. 74 MR. GARDINER: We were talking about the rate impact on a residential customer outgoing from a 30-year average to a 20-year declining trend normal, and both Mr. Warren and I were using the $17 reference that was in an earlier version of the J.163. That was corrected and the amount is $13. 75 And I referred to 1431 for the court reporter, and I found another 17 at 1421. 76 MR. SOMMERVILLE: That, in fact, was -- that reference is in the corrected Exhibit J.1.63. 77 MR. GARDINER: Right. 78 MR. PENNY: Thank you, Mr. Chairman. 79 Thank you, Mr. Gardiner. 80 MR. SOMMERVILLE: Mr. Warren. 81 CROSS-EXAMINATION BY MR. WARREN: 82 MR. WARREN: It's good news, Mr. Chairman, that the Board is ahead of me in terms of keeping up with the paper. 83 I assume, Mr. Gardiner, that there is -- if I were sufficiently diligent, there is a corrected J.163 somewhere that's got the $13 figure. I apologize, Mr. Gardiner, for using the old figure. I just didn't keep current. Thanks. 84 Mr. Gardiner and panel members, when we concluded yesterday, I had asked some questions about the weather hedges and Mr. Penny advised us that the issue would be dealt with by Ms. Elliott when her panel comes on. But in the interests of not being caught in a position where I should have asked a question of an earlier panel, let me just cover off a couple of points. 85 If you turn up, if you wouldn't mind for just a moment, Exhibit J.113, which is an answer to a Board Staff interrogatory number 13. 86 Panel members, in that interrogatory, the Board Staff asks some questions about the details of the weather hedges for 2002-2003, and Ms. Elliott responded by giving those details. And I just wanted to clarify on a couple of points. I assume, in looking at the answer, and based on what Mr. Penny told me yesterday, that Ms. Elliott will be able to tell us about the details of the hedge instruments themselves; is that fair? 87 MR. GARDINER: I think that is fair. 88 MR. WARREN: My question is: Will Ms. Elliott be able to tell us about who made the decision, first of all, who made the decision to enter into the hedges; and secondly, what was the information upon which that decision was based? Is that within her area or is that a question I should ask of either you or somebody else? 89 MR. PENNY: The answer to that is yes. It was a financial group transaction. Ms. Elliott is responsible for it. She can answer all the questions about it. 90 MR. WARREN: Including, Mr. Penny, the question about what information the decision was based on with regard to weather and weather risk? 91 MR. PENNY: Yes. You could ask Mr. Gardiner or this panel if they have any input to that, I believe the answer is no, but you could ask them that. But in general, the answer to that is yes. 92 MR. WARREN: Did you, Mr. Gardiner, have any input into the decision whether to enter the weather hedges? 93 MR. GARDINER: I had no input into the decision regarding whether Union Gas had -- would enter into such a contract. 94 MR. WARREN: The specific issue, I'm sorry to tax you on this, Mr. Gardiner, I just want to make sure it's covered off, the specific issue is, I'm assuming, and correct me if I'm wrong, I'm assuming that there was an assessment of the likelihood that it would be either a warmer or a colder winter before the decision was entered into. Is that a fair assumption on my part? 95 MR. GARDINER: You would ask to ask Ms. Elliott that. I'm not aware of that type of analysis. 96 MR. WARREN: Thanks, sir, I will ask her that. 97 I want to turn from those questions to try to drill down into the effect of the change in the weather normalization on some specific calculations. In that context, if you could turn up, please, Exhibit C.1, tab 4, which is the prefiled evidence, Mr. Gardiner, of you and Mr. Fogwill. 98 MR. GARDINER: I have C.1, tab 4. 99 MR. WARREN: Now, looking at the first paragraph on page 1 of 7, I see, in the second sentence, it reads as follows: 100 "Weather normalization is used to determine Union's demand forecast, storage and transportation allocations, gas supply planning, and rate design activities." 101 Now, of those four elements, the four being demand forecast, storage and transportation allocations, gas supply planning, and rate design activities, am I correct that the first two; that is, demand forecast and storage and transportation allocations, would have an impact on revenue calculations? 102 MR. GARDINER: I can speak to the demand forecast. Yes, it would for the demand forecast. The others I can't speak to. 103 MR. WARREN: Now, with respect to demand forecast, weather normalization is used to determine -- what are the factors that are used to determine demand forecast; and secondly, what is the relevant significance in that calculation of weather? 104 MR. GARDINER: Weather is a key demand driver explaining use per customer or total volumes. In a demand forecast period, one must make an assumption about weather. We refer to the assumption as the weather normal. In this demand forecast, we use the 20-year declining trend weather normal. 105 MR. WARREN: Now, is demand forecast -- what is the relationship between demand forecast and the NAC calculation? 106 MR. GARDINER: Demand refers to total through-put volumes, and total through-put volumes are obtained by the multiplication of total customers times NAC. NAC is normalized average consumption. The calculation is done on a monthly basis, and the monthly estimates are summed to get the demand volumes. 107 MR. WARREN: What I'm trying to get to, sir, and if you could turn up, please, Exhibit J.7.1, which is -- you'll be happy to know, Mr. Chairman, I have a corrected version of that. This is an interrogatory that was delivered by my client. 108 MR. GARDINER: I have it, Mr. Warren. 109 MR. WARREN: Now, this question was intended to elicit information about the major components of the delivery-related deficiency, and I'd like you to look at line items 2 and 3. The decrease -- line item number 2 is the decrease in forecast for heating degree days, et cetera, et cetera. This is the change in weather methodology. And we've agreed, I think, Mr. Gardiner, that the impact of that in terms of the revenue deficiency is $20.4 million; correct? 110 MR. GARDINER: That is correct. 111 MR. WARREN: Now, the decline in normalized average use per customer is a figure of $22 million; is that the correct figure? 112 MR. GARDINER: Correct. 113 MR. WARREN: Now, since weather has an impact on the calculation of normalized average use, or normalized average consumption, what I'm trying to get at, Mr. Gardiner, if you can help me, is -- let me put it simply: To what extent, if any, is there a double counting of the impact of weather in line items 2 and 3? 114 MR. GARDINER: There is no double counting. Item 2 identifies the impact on the revenue requirement of going from the Board-approved 1999 30-year average in 1999, to the current proposed 2004 20-year declining trend, and that gives you the $27 million. Yesterday we were talking about the other -- what's the difference of the 5 million. Well, it's also, the 1999 rate case, 30-year average set in 2002, and then going to the 22, and that's the five and 22 that gives you the 27, okay? So that's the impact of the heating degree days, going from one normal to another. 115 Item 3 says on a common normal, the 20-year declining trend normal, what has happened to usage? Usage has fallen on that normal from '99 to 2004, and we see that trend in our usage statistics and our analysis. And that trend, which on a common normal is declining, results in that amount of $22 million. 116 MR. WARREN: Let me tell you where my difficulty arises, aside from the fact that I'm dumb as a duck, let me tell me where my difficulty arises. If you can turn up in this context, Exhibit C.1, tab 1, appendix A. 117 MR. GARDINER: I have that reference. 118 MR. WARREN: And if you look at the first sentence on page 1, it says: 119 "NAC is affected by three factors: One, weather; two, energy efficiency improvements; and three, retail natural gas prices." 120 Now, my difficulty is this, Mr. Gardiner, that it would appear that, clearly, weather has affected line item number 2 of Exhibit J.7.1; that's the change in methodology, and results in an increase in the revenue deficiency. But weather also seems to have an effect, clearly has an effect if I read this exhibit clearly, Exhibit C.1, tab 1, appendix A, on the calculation of normalized average use. 121 Now, the analytical difficulty I'm having is this, sir: Weather isn't an abstract notion, it has an impact in specific areas of calculation; correct? 122 MR. GARDINER: Yes. 123 MR. WARREN: And the specific area where it has an impact is the calculation of NAC; correct? 124 MR. GARDINER: Yes. 125 MR. WARREN: Okay. Can you then help me out as to why it is the impact of weather wouldn't be reflected in just the normalized average consumption figure and nowhere else. 126 MR. GARDINER: There is no double counting. In item 3, as I mentioned earlier, the comparison of the 1999 consumption, weather normalized, with the 2004 20-year declining trend normal, compared to the 2004 consumption, also weather normalized, on the same 2004 declining trend, so now we have compared consumption values on the same normal, okay, so we're not going from one normal to another, we're on the same normal. The historic consumption data is weather normalized, so the '99 to 2002 monthly data is all weather normalized, because I can't compare actuals because actual weather is a NAC. So you normalize it. You say take the weather impact out. Tell me what the consumption would be at normal weather. So you do that for '99. Our forecast assumes normal, same normal. How did the consumption change? It's declined. That multiplied by the number of customers yields the change in consumption, multiplied by the unit rates, obtain the $22 million. So I'm comparing apples to apples. 127 MR. WARREN: But when you describe, at line item number 2, you use the term "consumption," because weather is translated into consumption figures. That's where it has its impact; fair enough? So is it not the case that the calculation of the $20.4 million is a calculation rooted in consumption? 128 MR. GARDINER: Correct. 129 MR. WARREN: And the $22 million on the line below it is a consumption figure which has been affected by weather. 130 MR. GARDINER: You're mixing up the impact of going from one normal to another normal. The second item is on the same normal. What are the consumption values in 1999 and 2004 on the same normal. So I'm comparing similar things. 131 MR. WARREN: All right. I have your answer. Thank you, sir. 132 Now, staying with Exhibit C.1, tab 1, appendix A, in the calculation of the normalized average consumption, you've got some figures on the succeeding pages about the percentage impact on the calculation of NAC of each of those. And am I right in assuming that weather is the most significant of the three factors in the calculation of NAC? 133 MR. GARDINER: That is correct. 134 MR. WARREN: If I take a pie, and we'll call it a hundred percent NAC, what is the contribution of weather to that 100 percent calculation? 135 MR. GARDINER: It is over 70 percent. 136 MR. WARREN: And energy efficiency improvements would be what? 137 MR. GARDINER: I'm -- somewhere around 20 percent. And I'm giving you rough numbers, Mr. Chairman, to give you approximations. 138 MR. WARREN: I appreciate that. Thank you very much, sir. And the retail natural gas prices are a 10 percent contributing factor? 139 MR. GARDINER: Right. 140 MR. WARREN: As I understand your evidence, the energy efficiency improvements that we're talking about are the non-DSM items; is that correct? 141 MR. GARDINER: That is correct. 142 MR. WARREN: How does DSM -- when I talk about DSM, we're talking about your DSM activities; correct? 143 MR. GARDINER: That is correct. 144 MR. WARREN: How, if at all, do your DSM activities factor into the calculation of NAC? 145 MR. GARDINER: In the forecast period for the years 2003 and 2004, the department that's responsible for developing and implementing the DSM plan provide us with their estimates of what the volume impacts will be in 2003 and 2004. They also advise us that these volumes have to be allocated 50 percent in the first year and the next 50 percent of that program year. There's sort of a flipping over effect. But nonetheless, we have these volume estimates for the residential customers, for the commercial customers. 146 And then based on this volume, dividing it by the number of total customers, I'm able to translate that into an incremental NAC amount, and that is then added to -- and it's a negative number so it's like a subtraction, it's subtracted from the NAC estimate that comes out of the econometric equations. So the econometric equations say the NAC should be this amount, the DSM program says, Based on the volume targets and number of customers, you should be reducing your NAC by an amount, we're talking small amounts, 10 to 15 cubic meters, and that's how the DSM is introduced into the forecast. 147 MR. WARREN: Is it possible, Mr. Gardiner, to calculate -- there are two levels of calculations. One is to calculate the impact of the revenue deficiency on a typical M2 residential consumer, and then the second level of calculation would be to calculate the impact of weather, energy efficiency, and gas prices on -- translated for an individual residential consumer. Can that calculation be done? 148 MR. GARDINER: I'm not sure, Mr. Warren, if I understand your question. 149 MR. WARREN: What I'm trying -- I'm sorry. We discussed a figure that the change in the weather normalization will have an impact on individual typical residential consumers of about 13 bucks, and I'm wondering if a similar calculation can be done to determine the impact of changes in efficiency and changes in gas prices. Can that calculation be made? 150 MR. GARDINER: The calculation can be made. I'd like to clarify that, though. The price assumption, the retail price assumption that we have in our forecast period is the retail prices that reflect the March 2003 QRAM for the commodity, and that was kept flat, and it reflects the current distribution rates that Union Gas has, and that hasn't changed. So on the retail energy price, we basically have no change in our price. 151 The energy efficiency variable is essentially a linear trend; it's very much a slow, gradual change over time. To give you a sense of how slowly it's changing, over the 12-year period, it only changed by 5 percent, so it's changing very, very small. So to make a reasonable assumption on the change, you wouldn't be changing it very much. 152 So the normalized -- where am I coming back to. I've normalized the weather, my price is fixed, and the efficiency doesn't really change very much, so we're going to end up with the same number, or very close to it. 153 I could go through the exercise, but I'd rather be talking about the filed forecast that we have before us. 154 MR. WARREN: All right. Let's leave it at that, then. What I'd like to do finally on the subject is NAC is if you could turn up an interrogatory delivered by my client, which is CAC Interrogatory No. 49. It's J.7.49. 155 MR. GARDINER: Yes, I have it. 156 MR. WARREN: The question that was asked is to provide the NAC levels for each of the service rate classes for the years 1994 to 2004 actual versus Board-approved. 157 If I turn over to the table, looking at the residential M2 class, the first line is actual and forecast NAC. My question is: In each of those years, is actual and forecast NAC the same number? 158 MR. GARDINER: The 1994 through 2002 are actual NACs that have been weather normalized using the 2004 declining trend weather normal as the reference normal. So all those show average use per customer, weather normalized, on a common normal. The forecast is shown by 2003 F, for forecast; 2004 F, for forecast, is the column headings, the titles. So '99 to 2002 are actuals; '03 and '04 are forecasts. 159 MR. WARREN: My question, though, sir, is a slightly different one. Would I be wrong in assuming that for each of the years '94 forward, there would have been, in effect, three levels of numbers? First of all, there would have been your forecast of what the NAC would be in each year; secondly, there would have been what the Board would have approved, which might or might not be the same number; and then the third number would be the actual number that came in. Am I wrong in that assumption, sir? 160 MR. GARDINER: That is correct. 161 MR. WARREN: So what I'd like, if I can get it, sir, is, for the years 1994 on, are those three numbers for the residential M2 class, which is what you forecast, what the actual numbers came in at, and what the Board approved. Can I get a revision to the schedule to show that? 162 MR. GARDINER: That question was asked in an interrogatory, and if you'd permit me some time, I'll find you the reference where we actually have that comparison. 163 MR. WARREN: Sure. 164 MR. GARDINER: May I refer you to Exhibit J.1.52, page 2 of 2. 165 MR. WARREN: So putting the two exhibits together, then -- 166 MR. GARDINER: Yes. 167 MR. WARREN: -- sorry. Putting the two exhibits together, I can get the three categories of information I'm looking for? 168 MR. GARDINER: Yes. If you look at column D, forecast, for residential M2, and this was the comparison that Mr. Warren was trying to get on the other table, that's the missing row of numbers. You'll note that six of the forecasts were high and four were low. 169 MR. WARREN: Thank you for that, sir. 170 The last area I wanted to touch on was the S&T calculations for this year. In whose bailiwick does that fall? 171 MR. POREDOS: That's mine, Mr. Warren. 172 MR. WARREN: I'd like to start, if I can, Mr. Poredos, with a very general expression, if I can, of what the current regulatory treatment for S&T revenues is. 173 MR. POREDOS: In terms of the revenues that are -- in EBRO 499 and beyond, there was a forecast of about 5.5 million, 5 million of which was put into rates. Any revenues above that would be put in through the deferral account and shared at 25/75 in favour of the customer. 174 MR. WARREN: Could I just interrupt you for a second, Mr. Poredos. The $5 million in rates, is that 90 percent of the forecast amount that you'd earn? Is that the way that was derived? 175 MR. POREDOS: The $5 million was 90 percent of, I believe the number was, 5.56 million, and it was split 90/10, that's correct. 176 MR. WARREN: So -- and again I'll let you get back to your answer in a moment. So the first step of the regulatory analysis coming out of 499 is that the first $5.6 million of forecast S&T revenue is split on a 90/10 basis between ratepayers and the company; is that correct? 177 MR. POREDOS: That's correct. In fact, the $5 million is basically guaranteed to customers, whether we make it or not. 178 MR. WARREN: And that's the amount that's embedded in rates, and was embedded in rates in 499; is that correct? 179 MR. POREDOS: I believe it was back in 499 when that decision was made, yes. 180 MR. WARREN: I then interrupted you. For any amount of S&T revenue that's earned above the $5 million, how is that treated? 181 MR. POREDOS: Those revenues are accounted for in the deferral accounts and are split at an approved rate of 75/25; 75 percent to the customer and 25 percent to the shareholder. 182 MR. WARREN: Now, the estimate of S&T revenue for fiscal 2004, if I look at Exhibit C.1, tab 3, Exhibit A -- 183 MR. POREDOS: Are you referring to appendix A, sir? 184 MR. WARREN: I'm sorry, appendix A. C.1, tab 3, appendix A. Updated exhibit. 185 MR. POREDOS: Yes, I have it. 186 MR. WARREN: Your estimate for S&T revenue for fiscal 2004 is what? 187 MR. POREDOS: The estimate for S&T revenue is 20,761,000 . 188 MR. WARREN: And is it the proposal of the company that that be embedded in rates for fiscal 2004? 189 MR. POREDOS: No, that is not the proposal of the company. The company is proposing that, going forward for the test year, that we use the same provision that we had in previous years, beginning as early as 1999, where the 5 million be embedded in rates. Anything above that would be shared 25/75, which would mean in this case that the 20,761,000 would be shared at a rate of 75/25 in favour of the customer. 190 MR. WARREN: I'm sure this is in the evidence somewhere in the vast amount of evidence, but can you tell me for the PBR period 1999 forward, what have the actual S&T revenues been in each of the years following? 191 MR. POREDOS: In total? 192 MR. WARREN: For each of the years. 193 MR. POREDOS: Yes. I believe there's an interrogatory on that. 194 MR. WARREN: I'm sure there is, sir. 195 MR. POREDOS: I'm trying to remember which one specifically it was. 196 In Exhibit J.34.44, we actually provide the storage loans and balancing totals going back to 1998, which is one portion of the total, and on 34.45 we provide the other revenue totals. And I don't remember where we've had a total in the IRs, if someone could help me with that. 197 MR. WARREN: Would I be correct -- first of all, just to clear up the record. I wasn't able to find the totals anywhere in the record, and perhaps I could ask you this, Mr. Poredos: Could I get an undertaking from you, on the assumption that it's not somewhere summarized in the record, can I get an undertaking from you to tell me, for each of the years of the PBR period, that is from 499 on, what was the total S&T revenue earned by Union? 198 MR. POREDOS: Yes, we can do that. 199 MR. PENNY: Just for clarification. I don't think anything turns on this, but just so that I'm sure that it doesn't, you talk about in the PBR term from 1999, but recall that the actual PBR mechanism only applied from 2001 to 2003. I don't think anything turns on it. You want 2000, 2001, 2002, and 2003. 200 MR. WARREN: Yes. Thanks for that clarification. 201 MR. MORAN: Mr. Chair, that becomes undertaking N.4.1, an undertaking to provide the total S&T revenues for each of the years 2000 to 2003. 202 UNDERTAKING NO. N.4.1: TO PROVIDE THE TOTAL S&T REVENUES FOR EACH OF THE YEARS 2000 TO 2003 203 MR. SOMMERVILLE: Thank you. 204 MR. WARREN: Now, my very rough back-of-the-envelope calculation for each of those years, which could well be wrong and it's subject obviously to the completion of the undertaking, is that in each of those years Union was earning more than $5.6 million a year in S&T revenue. Would I be fair in my level of generality, Mr. Poredos? 205 MR. POREDOS: I believe we were, yes, subject to check. 206 MR. WARREN: Subject to check. And the question then comes down to this: Why, in light of the fact that in the PBR period you had been earning in each year more and in some cases, as I recollect, substantially more than what was embedded in rates, why you would not now embed the $20.7 million forecast in rates for fiscal 2004? 207 MR. POREDOS: The 20 million is an estimate, it's a forecast just like any other forecast. It does have risk in it. And each one of those service blocks may be higher or lower in any one year. The costs and revenues may move in any one year. And Union doesn't believe that the obligation should be there to put it into rates. That is an issue that, if you put it into rates, the downside risk is all on the shareholder, at a hundred percent. If we were to do that, we would likely want to have an equal sharing or a sharing mechanism on the downside as well as on the upside. 208 MR. WARREN: For each of the years that Mr. Penny was just referring to, 2001, 2002, so on and so forth, was there -- can I get what your forecast and actual S&T revenues were for each of those years? 209 MR. POREDOS: Mr. Warren, I believe we can get -- I know we can get you the actuals. Whether I can actually get the forecasts for each one of those years, I am uncertain. 210 MR. WARREN: Okay. Can I ask for an undertaking to see if you can get me that, and if you can, can you deliver the forecasts as well as the actuals. Perhaps we can just add it, Mr. Moran, to the earlier undertaking, on the understanding that the data may not exist; correct, Mr. Poredos? 211 MR. POREDOS: Yes. 212 MR. WARREN: Is that acceptable, Mr. Chair? 213 MR. SOMMERVILLE: It is. 214 MR. WARREN: Now, are there factors for fiscal 2004 that, in Union's view, would make the likelihood of reaching the forecasts particularly problematic? 215 MR. POREDOS: The market conditions, going forward, are much different than what they were in past years. In fact, of the 11 major customers we have, many of them may not exist anymore. In the last few years, we've probably made about $32 million, or transacted at a rate of $32 million with those customers. This year we'll be at a rate of about $8 million. The business has gone down by 75 percent with those customers. 216 The other reductions would require -- also, that we are moving about 6 pJs of storage from our S&T book back into in-franchise, or it's been removed from S&T. Three of it has been put to T-service customers that is are in-franchise customers, three of it is pertaining to long-term contracts which were signed at market that were a part of the Centra Gas business when we merged with Union and Centra back in 1998, I believe. Those contracts are coming up for renewal. They are not market. We are likely not to renew those. If we were to renew those, they would be put against the S&T book, but they would have to go -- we're assuming we're going to make a margin on that, obviously. 217 I think the other issues is there some transactional services that have been available in the past or opportunities with TCPL services that we not have in the future, that includes AOS, FT make-up. 218 As I've also put in my testimony, we're also terminating the hub-to-hub business which we had within Cana which is going to reduce opportunities. 219 And the other issue being that, going forward, we forecast on a normal year, so all the assets that are being used are being used as if it is a normal year. Previous years have generated additional revenues or additional opportunities, regardless of whether they were warmer or colder, but different than normal. What that does is it provides opportunities that we can then use those assets in some way to generate revenue. So from that standpoint, we forecast on a normal basis those additional revenues caused by weather are not in the forecast. That's not to suggest that they may not happen in the future; they may, and probably will because the forecast is not perfect. 220 MR. WARREN: My final question to you, panel, is this, and I guess it relates both to the forecast for S&T revenue and to a larger issue, and that is: What is to happen beyond 2004? Is it the intention of Union that the S&T forecast for 2004, that which the Board decides will be embedded in the rates, will that be the base for a new form of PBR regime? 221 MR. POREDOS: I don't think that I can speak to that. I'm not part of the PBR discussions. My focus is strictly on 2004. 222 MR. WARREN: Is there another panel who would be able to speak to that issue about the relationship between what the Board decides in this case and any prospective PBR regime? 223 MR. POREDOS: I believe that the PBR discussion, if it does happen, will happen after this case. I don't believe we have a panel that discusses PBR. But I could be corrected. 224 MR. PENNY: That's correct. This is a stand-alone cost-of-service application. 225 MR. WARREN: Those are my questions. Thank you very much, sir. 226 MR. SOMMERVILLE: Mr. Warren. 227 It may be most convenient to take our morning break now. It's a little early. But we would then carry through to, say, 1:00. In the interim, could intervenors sort out their order, also in light of the schedule and the timing estimates that we have for cross-examination of this panel going forward. 228 So we'll break until 10 to 11:00 Thank you. 229 --- Recess taken at 10:35 a.m. 230 --- On resuming at 11:00 a.m. 231 MR. SOMMERVILLE: Please be seated. Thank you. 232 RULING: 233 MR. SOMMERVILLE: The Board will approve the application and TransAlta will be recognized as an intervenor. There is the question of evidence, and we are mindful of Mr. Penny's concerns, but we are persuaded that it -- that the process is best served if your client is permitted to submit evidence. We would require that evidence to be filed no later than Tuesday of next week, that being the 14th. Union will be permitted -- I think the time frame for the Coral matter was a seven-day interval. 234 Is that adequate, Mr. Penny? 235 MR. PENNY: You mean seven days after -- like the 21st, in other words? 236 MR. SOMMERVILLE: Correct. 237 MR. PENNY: That would be satisfactory. 238 Mr. Kitchen is principally responsible for that. He just had a new baby, but he'll still be able to manage. 239 MR. SOMMERVILLE: He might appreciate the diversion. 240 If there are some difficulties that arise around that, Mr. Penny, please advise and we can -- we will address that. 241 MR. PENNY: Yes. 242 MR. SOMMERVILLE: So your application is successful, Mr. Vegh. We would expect your evidence to be filed no later than the 14th. You could expect reply from Union, barring unforeseen events, on the 21st following. It is our expectation that the evidentiary portion, the oral portion of this issue would arise during the course of the rate design panel, which is the last Union panel, and we have, I believe, scheduled the Coral Energy live evidence to follow immediately on that. And we would expect that same time frame for any oral evidence that TransAlta issued to adduce. 243 There is the possibility -- well, I won't speak to that at this stage. We'll await events and proceed on that basis. 244 Any submissions arising from the Board's ruling? 245 MR. PENNY: No, Mr. Chairman. 246 MR. VEGH: No, thank you, sir. I'll just ask permission to take my leave. 247 MR. SOMMERVILLE: Thank you, Mr. Vegh. 248 MR. VEGH: Thank you. 249 UNION GAS LIMITED - PANEL 4; RESUMED; GARDINER, POREDOS, ROGERS 250 P.GARDINER; Previously sworn. 251 S.POREDOS; Previously sworn. 252 B.ROGERS; Previously sworn. 253 MR. SOMMERVILLE: Mr. Thompson. 254 MR. THOMPSON: Yes, thank you, Mr. Chairman. I can't be here tomorrow, and others have been kind enough to allow me to move up in the batting order, and I appreciate their willingness to do that. 255 CROSS-EXAMINATION BY MR. THOMPSON: 256 MR. THOMPSON: Panel, as you know, I represent the Industrial Gas Users Association, and I have questions in all three areas with respect to the revenue forecast that's before us, the general service forecast, contract classes forecast, and the S&T forecast. 257 Just by way of background, I would like to put in historical context, if I could, the last time the Board evaluated and approved volume forecasts for Union. Am I correct that that was in the EBRO 499 case? 258 MR. ROGERS: Yes, that's correct. 259 MR. THOMPSON: And my understanding is that those were forecasts, I believe, for -- well, what fiscal year was that for? Was it for fiscal 1999, so they were forecasts made in 1998 for 1999? 260 MR. ROGERS: That's correct. 261 MR. THOMPSON: All right, thanks. And can you help me with the extent to which the Board has been provided with information periodically the extent to which actuals deviate from forecasts and the new forecasts for the following years. Has there been any regular surveillance reporting? Is that something you witnesses can address? 262 MR. ROGERS: I don't think that the three of us can address that question. I'm not aware of the process, and not responsible for the process, and neither are my colleagues. 263 MR. THOMPSON: Is there someone coming later that might be able to help us with that, Mr. Penny? Would that be something the financial group might address? 264 MR. PENNY: Well, I think so. I mean we report financials quarterly to the ERO, and that's the financial group that's responsible for that. That's the ongoing reporting that I think you're talking about. 265 MR. THOMPSON: All right. 266 Well, from the perspective of you, Mr. Gardiner, and you, Mr. Rogers, who develop these forecasts annually and then monitor them as the year progresses, have you been providing information to the financial group for filing with the Board's ERO on the monitoring of actuals versus forecasts since the Board last approved the forecasts? 267 MR. ROGERS: I'll speak for myself on this, and, Mr. Gardiner, you can clarify for your markets. The responsibility to report the volume and revenue actuals is the responsibility of Mr. Wayne Andrews within Union Gas, so as a sales group we do provide information. What Mr. Andrews does with it after that we've not privy to. So the answer is we do feed and approve the forecasts and the actuals and understand them, but we do not administer the process after that. 268 MR. GARDINER: That's my understanding as well. 269 MR. THOMPSON: Okay, thank you. 270 Let's move, then, to the reasonableness of the NAC forecasts for the general service classes, and as you've discussed with Mr. Warren, one of the central features with respect to this issue is the proposal to use the 20-year trend normal method instead of the 30-year average; is that correct? 271 MR. GARDINER: I'm sorry, Mr. Thompson, I missed the question, I think. 272 MR. THOMPSON: The use of the 20-year trend normal method is one of the central features to the NAC forecasts that are being presented in this case for fiscal 2004. 273 MR. GARDINER: Absolutely. 274 MR. THOMPSON: And we've had a lot of discussion about the implications of the change of moving from the 30-year average to the 20-year trend method with the previous panel, but the result of that, we learned yesterday, is a degree day forecast for 2004 which then gets used in developing the NAC forecast; have I got that straight? 275 MR. GARDINER: Yes, you have that straight. 276 MR. THOMPSON: Okay. And if we could turn up Exhibit C.3, tab 2, schedule 7. What you'll need to have in front of you for this series of questions is the exhibit that Mr. Warren, or you referred Mr. Warren to, Mr. Gardiner, Exhibit J.1.52. You should also have at hand Exhibit J.17.16, that's an IGUA interrogatory response. 277 MR. SOMMERVILLE: Your original evidentiary reference, Mr. Thompson, was C.3, tab? 278 MR. THOMPSON: C.3, tab 2, schedule 7. 279 MR. SOMMERVILLE: Thank you. 280 MR. THOMPSON: It has the NAC for the various classes from 1995 through to 2004 forecast. 281 MR. PENNY: And then we had J.1.52, and then we had J.17.6? 282 MR. THOMPSON: 16, 1-6. 283 MR. PENNY: 16, sorry. 284 MR. GARDINER: Just to make sure that we're on the same wavelength, Exhibit C.3, tab 2, schedule 7, J.1.52 and J.17.16? 285 MR. THOMPSON: Right. 286 MR. PENNY: And, Mr. Thompson, I think you're looking at a blue page, so it's C.3, tab 2, schedule 7, updated? 287 MR. THOMPSON: That's correct. 288 MR. PENNY: All right, thank you. 289 MR. THOMPSON: So the first one is entitled -- this is C.3, tab 2, schedule 7, updated, "actual and weather normalized NAC, normalized at 20-year declining trend general service customers by rate class, test year ended December 31, 2004." 290 Right? 291 MR. GARDINER: That's correct. 292 MR. THOMPSON: What we see in the top line for each of these rate classes, as I understand it, for the period through to 2002, is the actual average consumption in cubic meters. 293 MR. GARDINER: That is correct. 294 MR. THOMPSON: Okay. And then what's below is a forecast of what the normal consumption would have been in that year had weather been normal and had the 20-year declining trend been used as the weather method. 295 MR. GARDINER: That's correct. 296 MR. THOMPSON: Okay. And so just to put this in context, there are figures in the prefiled evidence that take it back to 1991 for certain rate classes. Do you recall those figures? I think they're figures 2, 3, 4, 5, and 6 -- 297 MR. GARDINER: Yes, I recall those, yes. 298 MR. THOMPSON: Okay. And so it appears that to develop these numbers shown in Exhibit C.3, tab 2, schedule 7, and the numbers shown in the figures which take it back to 1991, that what the company did is go all the way back to at least 1991, developing the normal number using the 20-year trend data. 299 MR. GARDINER: That's correct. 300 MR. THOMPSON: So it did it for each year from 1991 forward. Was that the beginning year, 1991? 301 MR. GARDINER: Actually, it's 1990. 302 MR. THOMPSON: Okay. So you went back to 1990, developed the 20-year normal trend based on 20 years of prior data; is that the way that worked? 303 MR. GARDINER: No. The actual NACs that you have on the blue page, C.3, tab 2, schedule 7, are all normalized on the common 2004 declining trend normal. So it's not that when we did '95 we were using the 20 trend normal that would have been up to, say, '93. No, no, no. It's all in the same normal. So then I can look at these numbers and say, on a common basis, what is happening to usage? 304 MR. THOMPSON: All right. So you used data for the 20 years ending 2002 to develop your method for normalizing, and then applied that to actual data for the years 1990 and following; have I got that straight? 305 MR. GARDINER: I think so, yes. 306 MR. THOMPSON: Well, is there -- did I say it too fast? 307 MR. GARDINER: Maybe say it again because I was trying to follow you. 308 MR. THOMPSON: Yes. The data that you used to develop the 20-year normal trend, I think you said, was data for the 20 years ending 2002. That gives you the basis for the adjustment that you make to the actual to develop normal. 309 MR. GARDINER: Correct. 310 MR. THOMPSON: And then you use that data and then went back to 1990 actuals and said, I apply that trend to that data, my normal is X. 311 MR. GARDINER: Okay. 312 MR. THOMPSON: Is that right? 313 MR. GARDINER: No. The purpose of a schedule like schedule 7 is to show you, in each year, on an annual basis, what consumption is on a normal basis and on an actual basis, okay? The actual forecast, using the econometric equations, is based on actual consumption, actual weather, actual prices, and the estimate, on an actual basis, of what energy efficiency is, the index, okay? So the econometric forecasts are premised on actuals, okay? The purpose of this blue-page table is really to show, on an annual basis, you know, here's what an actual -- it was a warm year, therefore the NAC was low, but had it been normal, what would it have been? 314 Another role of this is to get us a very general sense of what is happening to NAC, and that was the purpose of those figures, to sort of give an eyeball view of what the NAC is doing. But I want to say, we don't eyeball the NAC, put a line through it and say that's our forecast. There are equations that we use and they have those variables that I was talking to Mr. Warren about. 315 MR. THOMPSON: All right. Well, I don't know that that was responsive to my question. All I'm trying to get at is this, Mr. Gardiner: If you look at Exhibit J.1.52, page 2, in the NAC column, in items 1 to 8, you'll see there "forecast" -- 316 MR. GARDINER: Correct. 317 MR. THOMPSON: -- and that's forecast normal, right, for each of those time periods. 318 MR. GARDINER: Correct. 319 MR. THOMPSON: All right. And then the footnote tells us these forecast normals were derived using the 30-year method. 320 MR. GARDINER: Correct. 321 MR. THOMPSON: Okay. So all I was getting at, if we had blue sheets, like C.3, tab 2, schedule 7, that used the 30-year normal method, the number appearing at lines 2, 4, 6, 8, 10, 12, and 14 would be higher. 322 MR. GARDINER: If schedule 7 was redone on a 30-year normal basis, average normal basis, the actual -- the actual NAC -- no, the actual doesn't change. 323 MR. THOMPSON: The actual doesn't change -- 324 MR. GARDINER: The normal and the forecast numbers would change. 325 MR. THOMPSON: Change. 326 MR. GARDINER: Yes. 327 MR. THOMPSON: And how much they would change on a rate-class basis we do not have in the record for each and every year, but we do have some indicators of this. One is this Exhibit J.1.52. If I inserted those various numbers for the periods starting at 2000 and going back, and inserted them opposite what you have in the blue sheets, I could get some indication of the extent to which the numbers would be higher. For example, line 2 in the column 2000 in the blue sheets is 2688, but using the J.1.52 and the 30-year method, the number would be 2927. 328 MR. GARDINER: I accept that. 329 MR. THOMPSON: Okay. And we can do that for the other numbers. I don't want to waste time doing it. But what we asked in IGUA J.17.16 is the extent to which this change in methodology affects these numbers. And if you go to J.17.16, at page 2 of 3, and again just taking the M2 class, this is in the answer B, C, and D. Do you see that? 330 MR. GARDINER: Yes. I see that. 331 MR. THOMPSON: What this schedule is showing the difference, as I understand it, between the number, the NAC number that falls out from applying the 20-year trend to the number that would fall out from applying the other different methods. 332 MR. GARDINER: That is correct, Mr. Thompson. 333 MR. THOMPSON: Okay. And Mr. Fogwill is responsible for this, but he's not on this panel so I'll have to ask you, but looking at the residential class, it's showing there for the 30-year average a number of 131. Do you see that? 334 MR. GARDINER: Yes, I do. 335 MR. THOMPSON: And I take that to be for 2004; am I right? 336 MR. GARDINER: That is correct. 337 MR. THOMPSON: All right. And so if we then look at the blue sheet, C.3, tab 2, schedule 7, for 2004, we have the number 2578 for normal and for -- for normal and forecast, line 2. 338 MR. GARDINER: Yes. 339 MR. THOMPSON: And this response to IGUA J.17.16 is telling me that number would be 131 units higher if the blue sheets had been done using the 30-year weather normal. 340 MR. GARDINER: I'm with you, okay. 341 MR. THOMPSON: That's what it's telling us; is that correct? 342 MR. GARDINER: That's correct, yes. 343 MR. THOMPSON: Okay. And we can see the number would be 92 units higher if we used the 20-year rolling average; would be 126 units higher if we used the 25-year rolling average. So if you stick with rolling averages, the number is in the same ballpark. It's higher by something between 90 and 131. 344 MR. GARDINER: Yes. 345 MR. THOMPSON: Okay. And if we go to the trend approach, then, if we had a 30-year trend instead of 20-year trend, the number would be higher by 14? 346 MR. GARDINER: That's correct. 347 MR. THOMPSON: But if we had 25-year trend instead of 20-year trend, the number, according to column E, would be 28 units lower. 348 MR. GARDINER: Yes. 349 MR. THOMPSON: Okay. So the numbers oscillate around, in effect, what are the red and yellow lines on this chart in Exhibit M.2.3. 350 MR. GARDINER: Yes. 351 MR. THOMPSON: Okay. So that's the impact of moving from 30-year normal to 20-year trend; the numbers get pulled down. Right? 352 MR. GARDINER: Yes. 353 MR. THOMPSON: And so the impact of moving from the red line to the yellow line on this chart on M.2, tab 3, is to pull down the normal numbers that are the output of the process. 354 MR. GARDINER: That's correct. 355 MR. THOMPSON: And the cost to ratepayers for that in the 2004 test year is $20.4 million for the weather component. 356 MR. GARDINER: That's right. 357 MR. THOMPSON: Okay. And I'll come back to this chart in a second. But within the numbers that are in the blue sheets, within this NAC forecast number that you developed, there are a number of things going on, as I understand it. We have the weather component, we have the energy efficiency component, we have the retail pricing change component, and you gave the percentages to Mr. Warren with respect to those of 70/20 and 10. Just stopping there. What was the source of the information that you were referring to to get those percentages? 358 MR. GARDINER: That results from the econometric equations. 359 MR. THOMPSON: Okay. And then in addition to the numbers that show up on the blue sheets, we have an adjustment for marketing; am I right? 360 MR. GARDINER: Correct. 361 MR. THOMPSON: And then we have an adjustment for DSM. 362 MR. GARDINER: That's right. 363 MR. THOMPSON: So within the component -- within each number at line 2, for example, of M.2, Exhibit C.3, tab 2, schedule 7, within the 2578 there are, in essence, five pieces; the weather piece, the energy efficiency piece, the retail pricing piece, the adjustment for marketing piece, and the DSM piece; is that right? 364 MR. GARDINER: Yes. And then there's actually another piece. 365 MR. THOMPSON: What's the other piece? 366 MR. GARDINER: The reasonablity test. 367 MR. THOMPSON: The what test? 368 MR. GARDINER: The reasonablity test. After we've gone through the five steps that Mr. Thompson discussed, we step back and we apply the reasonablity test to it. If the estimate for 2003 falls within the reasonable range as identified by the reasonablity test, we don't change the estimate. If it falls out of the range, we bring it to within the range. That's the last step in the forecasting process. 369 MR. THOMPSON: Now, is it anywhere that those pieces are displayed separately? 370 MR. GARDINER: Yes. If you permit me, I'll find it in the IRs, and the pieces are shown. 371 MR. THOMPSON: Yes. 372 MR. GARDINER: Bear with me a bit. 373 MR. THOMPSON: I know it's a monumental record to get through, and I didn't find it so I can understand your dilemma. 374 Can anybody help us with the number? 375 MR. GARDINER: There is an interrogatory response where we broke it out by certain class. It's a fairly large table. 376 MR. AIKEN: I might be able to help, Mr. Chairman, Mr. Gardiner. In the response to J.34.33 there was a spreadsheet that was filed, and that does have some of the breakdown. 377 MR. GARDINER: Thank you. Yes, thank you. J.34.34, page 2 of 2. And if we look at the column on the left, under market water heating DSM plan efficiency, there's sort of a column, and if we look at the residential rate M2, which is the second grouping of 2-02, 2-03, 2-04 numbers, you will see under DSM that the adjustment for the DSM plan for 2-04 is negative 14 cubic meters. The marketing plan incremental NAC is worth 40, so we would add 40. And in that year, to recognize some changes taking place on water heater efficiency standards based on information from the federal government, we also made a small reduction explicit to that new standard for water heaters to the negative 2. 378 Columns under equation 1 and equation 2 are specific to the IR that was being asked, and those I won't comment on right now, but I'll draw you to the column that's called the "Base Case NAC," okay? 379 The econometric estimate would be -- it's not shown here. But if you take the econometric and add the 40 and subtract the 2 and the 14, you get the econometric estimate. And then we made this reasonability test adjustment of the 14 under the column that says "RESNBTY," "ADJ" for adjustment, you come up with the final NAC of 2,578. 380 So that's the forecasting method we used. 381 MR. THOMPSON: Okay. Just to follow -- I'm sorry, were you finished? 382 MR. GARDINER: Yes. 383 MR. THOMPSON: Okay. The DSM adjustment, is that mechanical or is that judgmental? 384 MR. GARDINER: No. It's based on the DSM plans that Union Gas has, and these are the plans that are submitted to the Board. So, no, these are... 385 MR. THOMPSON: So once you know the budget, you can calculate that out? 386 MR. GARDINER: Yes. 387 MR. THOMPSON: The marketing plan, is there an element of judgment in that? 388 MR. GARDINER: That is developed by the channel management group, under Mr. Paul Sherville and they, based on their information working with retailers and developers and builders and from discussions and other information they come up with a plan and produce the numbers. So there is some professional marketing assessments that are made, yes. But there's a lot of information that comes in. 389 MR. THOMPSON: Okay. And the water-heater efficiency, has that got some elements of judgment in it? 390 MR. GARDINER: That was based on a technical assessment outcoming from the change in the standards. 391 MR. THOMPSON: And then you have these responsibility adjustments both -- 392 MR. GARDINER: Reasonablity. 393 MR. THOMPSON: Sorry, reasonablity. I wouldn't want to use the word responsibility. Freudian slip. 394 Reasonablity both at the equation 1 stage and the base case stage? 395 MR. GARDINER: No. In this IR someone had asked us what it would look like if you went through and did the full exercise using only using equation 1 or equation 2. In the filed evidence, the econometric equation estimate, say, for the residential M2, is a marriage of equation 1 and equation 2, a simple average of those two numbers. And then we assess that estimate against the reasonablity test, okay? 396 MR. THOMPSON: Is reasonablity judgmental or mechanical? 397 MR. GARDINER: Mechanical. 398 MR. THOMPSON: And in 25 words or less, can you just tell us how you have a mechanical reasonablity test? 399 MR. GARDINER: I'm glad that you asked. May I turn you to Exhibit J.26.28. On J.26.28, the mechanical exercise is presented. Historically we know that when we looked at the January to March NAC in total, so the sum NAC for those three months, expressed as a percentage of the annual NAC for those years, we see a relatively interesting stable trend. So under the residential M2 column you see that the numbers go from 46 percent to 46.7 percent, and there is a little bit of variation in there. 400 That trend, when you plot it and look at it, is a very interesting stable trend, so you can project it. So we do. We put a trend line through that and we get 46.8. At the same time I say I see some variation in those numbers and from that I can calculate one standard deviation. So I get an estimate, my goalposts, the low trend and the high trend, the 46.3 and the 47.3. 401 Now, when the NAC forecast was prepared, I'm in early April and I have the historic numbers for January to March 2003. So what I do is I say, Okay, if my NAC number for those three months is such and I apply the 46.3, I get an annual estimate; if I apply the 47.3, I get another number. So those numbers are my boundaries. I look at my NAC forecast and I ask myself, Is it in the boundary? If it is, it passes; if it isn't, I move it back to the boundary. And that's the mechanical process. 402 MR. THOMPSON: And these supplements to the, if you will, the weather norm component, you would use those whether you were using the 30-year average method or the 20-year normal or some other; correct? 403 MR. GARDINER: Yes. 404 MR. THOMPSON: So these operate around the weather-normal method that is used in the process, okay. 405 And so just to get these numbers straight, the impact of staying with the 30-year average method instead of moving to the 20-year trend method for 2004 is $20.4 million. 406 MR. GARDINER: Right. 407 MR. THOMPSON: Okay. But if we took that back year by year, back to 1999, the total number that we would get for those year-by-year impacts would be the number that's shown in the CAC exhibit, correct, the 27 million? 408 MR. GARDINER: That's the J.7 -- 409 MR. THOMPSON: J.7.1. I think that's... 410 MR. GARDINER: The $27 million represents the difference between assuming a 30-year average a la 1999, and the 2-04, so it's for the one year, 2-04. 411 MR. THOMPSON: 2-04 compared to 1999, it's not cumulative. 412 MR. GARDINER: No, it's saying take that '99, 30-year average and use it. It's for 2-04. 413 MR. THOMPSON: It's 2-04, but the comparator is 1999; the 20.4, the comparator is existing rates. 414 MR. PENNY: I explained this the other day. The 20.4 is 2004 with the difference between 2004 with 30-year average and 2004 with 20-year trend. 415 MR. THOMPSON: Okay, fine, I have that one straight. But the other number relating to what I understand you to be telling Mr. Warren relates to the other components of NAC. They also are on the decline. 416 MR. GARDINER: Correct. 417 MR. THOMPSON: Okay. And when we talk about the other components of NAC also being on the decline, that wraps up, as I understand it, these other adjustments that we were talking about. 418 MR. GARDINER: Yes. 419 MR. THOMPSON: And it wraps up energy efficiency, retail, adjustment for marketing, adjustment for DSM -- sorry, excludes adjustment for DSM, but it wraps up the adjustments -- sorry, the energy efficiency, the retail marketing -- the retail pricing, adjustment for marketing, and the reasonability test into one. Have I got that straight? 420 MR. GARDINER: Yes. 421 MR. THOMPSON: Okay. And so those pieces have been changing over the years 1999 to 2004, based on your evidence; correct? 422 MR. GARDINER: Correct. 423 MR. THOMPSON: And just to get the impact of sticking with those pieces of the puzzle, we asked you a question in IGUA J.17.16, which was question F. We said if you just, instead of forecasting some declines in those pieces of NAC, keep that piece of NAC at the level it was in 2003, and the answer that came back: The impact of 2004 NACs equal 2003 NACs is estimated to reduce the revenue efficiency by $6.1 million. 424 Now, I took that to be a piece of the second component of change that you're describing in the response to Mr. Warren's Exhibit J.7.1. 425 MR. GARDINER: Yes. These -- 426 MR. THOMPSON: Did I understand that correctly? 427 MR. GARDINER: I believe you did, yes. 428 MR. THOMPSON: Okay. And so coming to 2004, then, if the 30-year revenue -- 30-year weather normalization method continues, its impact on the 2004 revenue deficiency is to reduce it by $20.4 million; correct? 429 MR. GARDINER: The $20.4 million is the -- 430 MR. THOMPSON: It's weather only. 431 MR. GARDINER: Correct. 432 MR. THOMPSON: All right. And then if the decline in the other components of NAC that you're forecasting is not approved but held at its 2003 actual level, that would reduce the deficiency by a further $6.1 million; is that correct? 433 MR. GARDINER: That's correct. If you held the energy efficiency index at its 2003 level, and did not recognize the efficiency that takes place in the marketplace as people build more efficient homes and replace their furnaces -- and I could sing a song, and I won't, Mr. Thompson -- you would result in $6 million of ... 434 MR. THOMPSON: But does that -- 435 MR. PENNY: Just for clarification, I think Mr. Thompson referred to that as an actual number, and, of course, that's not an actual number because we're still in 2003. 436 MR. THOMPSON: Sorry. The 2003 NAC is actual and estimated at this stage? 437 MR. GARDINER: At this stage it's the bridge-year estimate for 2003. 438 MR. THOMPSON: Which is? 439 MR. GARDINER: Which is a combination of five months actual NAC on the tool for normal and seven months of forecast estimate. 440 MR. THOMPSON: Okay, thanks. 441 But does the 6.1 million just capture energy efficiency or the energy efficiency and the other adjustments? 442 MR. GARDINER: Well, it's essentially energy efficiency because we've frozen the price at current levels and the March QRAM. 443 MR. THOMPSON: All right. So it doesn't capture changing the adjustments that you've made for marketing or reasonablity. 444 MR. GARDINER: Yes, thanks for -- that's true. If you look at that other reference, there were adjustments for the marketing plan. So if we froze -- if we froze the NAC at 2003, we would not capture the increase in the marketing incremental NAC, and as well, we would not benefit from the DSM accumulation from 2-03 to 2-04. So those also would be in the $6 million. So combination of efficiency and these two increments that we would not be recognizing. 445 MR. THOMPSON: Okay. I'll move on from this now. Just before I do, I want to get two other numbers in the record, if I could. I wanted to write on Exhibit C.3, tab 2, schedule 7 the heating degree days for the north and the south that are the base for that scenario, and my notes are that Mr. Fogwill said it was 4,953 for the north and 3,996 for the south. Would you take that, subject to check? Or if I've got them wrong, tell me. 446 MR. GARDINER: I'm looking that up. The 4,953 is correct. For the south, I'm just making another check, I have a number of -- I have a number of 3,677. 447 MR. THOMPSON: Maybe I didn't get that right. 448 MR. SOMMERVILLE: That's what my note indicates. 449 MR. GARDINER: 3,677. 450 MR. THOMPSON: Maybe the 3,996 was the combined. 451 MR. SOMMERVILLE: That's correct. 452 MR. THOMPSON: What was it again? 453 MR. SOMMERVILLE: 3,677. 454 MR. THOMPSON: Thank you. My apologies. 455 I just wanted to write on the Board interrogatory response J.1.52 the heating degree days for 2004. We can write it wherever we want it. What would be the heating degree days for 2004 for the north and the south, under the 30-year weather normalization method? And if it's not readily available, I'd be happy with an undertaking. 456 MR. GARDINER: I was prepared for this question. The number is 3,919 for Union south, and 5,224 for Union north. 457 MR. THOMPSON: Great. Thanks very much. 458 I want to come back to, then, this chart that appears as part of Exhibit M.2.3, please. 459 MR. PENNY: Could I get that reference again, Mr. Thompson. 460 MR. THOMPSON: It's in Mr. Shepherd's cross-examination materials, M.2.3. If you stay up late enough and look at this chart, you can get a lot of questions. 461 MR. GARDINER: I have it. 462 MR. THOMPSON: Okay. I just want to use the chart to illustrate a point that I had raised with Mr. Fogwill yesterday, perhaps ineloquently, but that is the impact of moving from the 30-year method to the 20-year trend method. And when I say "impact," impact on ratepayers and shareholders. And would you agree with me that, taking the -- the red line depicts the 30-year trend, if you just assume that that's more or less accurate. Would you agree with me that the peaks above the red line, looking backwards, represent the potential for the shareholder to overearn in any year as a result of weather, and the peaks below the red line represent the potential for the shareholder to underearn? 463 MR. PENNY: With respect to weather. 464 MR. THOMPSON: With respect to normal weather. 465 MR. GARDINER: I will agree with you. 466 MR. THOMPSON: Okay. And so you see historically from the period '71 through to the mid-'80s, roughly, using the 30-year weather-normal method, the potential for overearnings, based on the peaks above the red line, substantially exceeded the potential for underearnings due to weather? That's what the chart shows. 467 MR. GARDINER: I see on the chart actuals from about 1982 onward, where the actual weather was well below the 30-year average. And to make this point quite clear, if we look at Exhibit C.1, tab 4, page 3 of 7, this is the thermometer figure. 468 MR. THOMPSON: Now, just answer my question. 469 MR. PENNY: Sorry, Mr. Thompson, he is answering your question. 470 MR. GARDINER: If I see that 30-year trend line, the red line, and I see that after 1982, the weather is basically below, and if we averaged all those blue lines as deviations from the red line, that's where we got our 7.6 percent difference over the period. I was going to school in 1976, and yes, I may remember one winter at McMaster we got some snow. But since 1982 it's been very, very warm. And on C.1, tab 4, page 3 of 7, you'll see that of the 18 years, only three have been colder and 15 have been warmer than the 30-year average. So this is a great symmetry of 13 and 15. Whereas, if you put a 20- year trend and roll that through, and that's the yellow line, through the same period, you get an 11/7. That's more symmetric than 15/3. 471 So this is the issue, the reason why we went to the declining trend, is because it's not fair to be doing the demand forecast when your normal is up here and the reality is doing this. I don't know if the court reporter can see my hand, but the straight hand out and then there's a trend. There's a strong trend in the material. 472 MR. THOMPSON: Mr. Gardiner, back to me. I was talking about the period '71 to '82, okay? I was here before this Board in that time frame, and I didn't hear the company telling me the red line was too low, okay? And so what we had in that time frame was the potential for overearnings appeared to greatly exceed the potential for underearnings. The peaks above the red line were more frequently above it than below it. But I take your point. Let's bring it forward from '82 on because that is when the situation changes. 473 But the reality is -- and so your point is the situation kind of flipped around. The peaks were now under the red line so you want to pull the line down; right? 474 MR. GARDINER: It's not that we intentionally wanted to pull the line down. 475 MR. THOMPSON: Well, it just didn't fall off a shelf. 476 MR. GARDINER: No. What happened was back in '98/'99, we were noticing that, using a 30-year average, which was our approved method, that our actuals just -- as the thermometer chart shows, the actual volumes out there for the actual weather was coming in much lower than the 30-year average. At the same time, '98, warmest year on record, 500 people die in Chicago, we start hearing from the scientists, about global -- I can't even remember, I'm the one that -- global weather changes, and then we started to look at various methods that other utilities used, got outside advice, but ultimately did our analysis, saying let's look at all these methods and come up with a method that's stable, simple, sustainable, and recognizes that in the big world something is happening. And the weather panel previous gave you a large discussion on that. And that's how we ended up with the 20-year declining trend which, as a forecaster, gives me a fair chance of getting it right on a normalized basis, because I want the symmetry, I want to be 50/50. 477 MR. THOMPSON: I just want to talk about the impact, Mr. Gardiner. What this does, if you pull the red line, the red line drops down to the yellow line, you've agreed with me that in 2004 that adds cost to the ratepayers of $20.4 million; right? 478 MR. GARDINER: Correct. 479 MR. THOMPSON: And what it does is reduces the company's risk of underearnings by the amounts by which it's cutting these peaks below the line off. So if we shaded in above the yellow line and before the red line, what adding $20.4 million to the ratepayers' bill does is it eliminates the shareholders risk of underearnings as shown between the yellow and red lines for the peaks that fall below the red line; is that correct? 480 MR. GARDINER: No, I disagree. Over that period, Union Gas's rates were reviewed and approved by the Board on the basis of the 30-year average normal. The rates were set on that basis. Over that time period, the weather was much warmer. What this means under cost of service is that the rates, given the forecast based on the 30-year normal, were actually too low. So I would argue that as consumers, we got a pretty good deal. But you have to balance that against the company too. It has to be that. So what we're trying to do here is redress the symmetry that existed back in the '80s, when, based on the information available, people said 30-year average, to today, where we want the symmetry around the normal. So that the process of cost of service and rate design is based on a symmetric weather normal. 481 MR. THOMPSON: Compared to sticking with the method and changing it, I suggest to you it's as plain as this graph. You reduce your exposure to underearnings. That's a consequence of the proposal. That's one of the reasons you make it. 482 MR. PENNY: Is that a question? 483 MR. THOMPSON: That's a shouting question. Is that correct? 484 MR. PENNY: Because it does sound like argument to me, Mr. Chairman. 485 MR. THOMPSON: Well, I'm trying to get the witness to agree that that's a fact. 486 MR. GARDINER: If the company is on a 30-year average, the likelihood is that the company, if the future weather is the normal, will not have $20.4 million, right, and therefore won't be able to recover the costs that are essentially fixed to deliver the gas. So the 30-year normal is an unfair normal. 487 MR. THOMPSON: All right. Let's move on. Not only does it reduce the shareholder's exposure to underearnings by dropping this line down, it also increases the prospect for the shareholder of overearnings. 488 We've heard from the previous panel we can expect oscillations in this blue line above and below the yellow line. Would you agree with the proposition that this proposal, if approved, increases the shareholder's prospect of overearnings? 489 MR. GARDINER: I disagree. When I look at this chart I see oscillations on both sides, the blue line, on both side of the yellow line. I heard the respected gentleman, I won't say gentlemen, I heard the respected scientists say that their expectation is for the blue line to oscillate or to continue trending down, and the yellow line, which is the 20-year declining trend normal, by design, fits through that data. The red line is -- there is no oscillation about the red line after 1995 and '96 -- 490 MR. THOMPSON: I'm talking about oscillation around the yellow line. If you get what you're asking for, the oscillation above the yellow line and below the red line, if you get your yellow line, you're going to increase the shareholder's potential for overearnings. 491 MR. GARDINER: Only as compared to the 30-year average, because under this forecast, which is the evidence before the Board, we're saying we're prepared to take the weather -- actual weather risk, ups and downs, about the yellow line. The actual weather will move somewhere on the cold side of the yellow line or on the warm side of the yellow line. We believe that by using a 20-year trend, that we will try and have more symmetry in that than what we would get with a 30-year average. 492 MR. THOMPSON: Let me just take one more stab at it. At the expense of the ratepayers of $20.4 million, you will kindly take the overearnings potential above the yellow line; is that right? That's what I heard you say. 493 MR. GARDINER: When it's colder than the yellow line, yes, the shareholder will benefit. But when it's below the yellow line, which is -- on the symmetric basis, the shareholder will not benefit. It's a balance, as I understand cost of service and rate-making. It's not my area, but I have some very high-level knowledge of it. 494 MR. THOMPSON: I see. So we pay 20.4 to enable the line to move down, and to the extent the blue line goes above the yellow line but lower than the red line, you keep that money. Is that fair? 495 MR. GARDINER: It's just to bring back the risk -- potential risk profile of weather back to a symmetric basis. That's what it is. 496 MR. THOMPSON: So you say it's fair. 497 MR. GARDINER: Yes. 498 MR. THOMPSON: I see, all right. Well, we'll argue that. 499 Now, was there any thought given to -- let me back up. The transition from a 30-year to a 20-year, looking at its impacts on the NAC for rate classes, just taking the 131 that was in the IGUA exhibit, expressing it as a proportion of the 2561, I made it to be about a 5 percent impact. 500 MR. GARDINER: That's correct. 501 MR. THOMPSON: To me, that's a fairly significant change. Was there any thought given to some sort of transition, some sort of system where we could monitor whether this really was going in the right direction? 502 MR. GARDINER: I can't answer that. I'm responsible for the NAC forecasts. That would be -- that's not something I can answer. 503 MR. THOMPSON: Whose bailiwick was that? Is somebody yet to come who is capable of speaking to that? 504 MR. GARDINER: That would have to be an executive decision, and I don't have any information as to whether they did or didn't. 505 MR. THOMPSON: All right. Well, I'll pass that to others when they arrive. 506 Let's move to the other piece of this NAC which is the customer forecast numbers. This is in the prefiled evidence, I think, somewhere, the blue sheets. I just want to understand from you, Mr. Gardiner, what is the customer forecast, the general service customer forecast number for the 2004 test year? 507 MR. GARDINER: I have that. May I refer you to Exhibit C.3, tab 2, schedule 1, updated. That's the August 2-03 table. And the customer forecast is shown under column A. 508 MR. THOMPSON: So for your area it's the one -- 509 MR. GARDINER: 222015, not rate 16. And there's a certain number of rate 10s that are in Mr. Rogers' market. But essentially the majority, 1.2 -- we're only talking about 200 customers, so 1222015, for the purposes of discussion, is ... 510 MR. THOMPSON: And was that derived from a five and seven for 2003, and then a forecast for 2004. 511 MR. GARDINER: The numbers you see here are year-end numbers, so both the '03 and '04 numbers are forecast estimates. 512 MR. THOMPSON: All right. But the '03 number which would appear under the C-4 schedule, the equivalent schedule -- 513 MR. GARDINER: It's a year end, so December is a pure estimate. In '03 you overlay your first five months of actuals, so the customer stats come in and you overlay that to your original projection and then you take your remaining seven. 514 MR. THOMPSON: That's what I was just trying to see. C.4, tab 3, schedule 1 is a five actual, seven forecast, that's for 2003? 515 MR. GARDINER: Yes. 516 MR. THOMPSON: And then increments to that which would appear in C.3, tab 2 are entirely forecast. 517 MR. GARDINER: Yes. In fact, if I refer you to Exhibit B.1, tab 3, appendix B, there is a table that shows the actual customer attachments, and that's sort of the increase at year-end in the number of total customers. There is a small recognition of demolition that is taken away from these attachment numbers, the numbers like 700 customers are assumed to leave the system either because it's an old house or ... 518 MR. THOMPSON: But you get the information about additions from the -- 519 MR. GARDINER: Marketing -- 520 MR. THOMPSON: -- the rate-base group, do you? 521 MR. GARDINER: It's from the channel management marketing group. 522 MR. THOMPSON: Okay. I think they're yet to come, some of them are yet to come. Okay. Thanks. 523 Let's move to, then, I guess you, Mr. Rogers. This is the contract rate classes, and your testimony is at C.1, tab 2. 524 MR. ROGERS: That's correct. 525 MR. THOMPSON: And on page 4 of 5 of C.1, tab 2, in the update, you provided what you call comparisons from the 2003 blue page, 2004 white page, 2004 blue page, and those are references, as I understand it, to the C.3 and C.4 exhibits, are they? In other words, the 2003 blue page that you refer to in that exhibit, am I correct that that refers to C.4, tab 2, schedule 1, but it's confined to the contract rate classes, the volume there shown? 526 MR. ROGERS: Could I have that reference again, please. 527 MR. THOMPSON: Yeah. C.4 -- for 2003, blue page, we go to C.4, tab 1 -- sorry, tab 2. C.4, tab 2, schedule 1, column B, for the contract rate classes, lines 10 to 19. I'm just trying to get the source of this information. 528 MR. ROGERS: That is correct. 529 MR. THOMPSON: All right. And similarly, the 2004 white pages, blue pages, come from C.3, tab 2, schedule 1, blue and white. Have I got that straight? 530 MR. ROGERS: I'm just looking for it. That is correct. 531 MR. THOMPSON: Okay. And just to try and put -- your total contract forecast for the test year now is 9,351. Is that 10(6)m3. 532 MR. ROGERS: That's correct. 533 MR. THOMPSON: And that's a slight increase over your current expectations for 2003 of 9,260, 10(6)m3. 534 MR. ROGERS: That's correct. 535 MR. THOMPSON: Just to put in contrast how your actuals and forecasts play out over the years, I wanted to have you to turn up, if you could, Exhibit J.17.15. This is an IGUA interrogatory. 536 I wanted to start in the year ending December 31, 2000, so I'd like you to just go to page 7, if you wouldn't mind. 537 MR. ROGERS: Page 7? 538 MR. THOMPSON: Do you have that, sir? 539 MR. ROGERS: Yes. 540 MR. THOMPSON: Okay. And at line 12 we see the total -- this is in column B, the total forecast in that particular year was -- well, let's call it 8.8 10(6)m3. 541 MR. ROGERS: 8.783. 542 MR. THOMPSON: In column B, okay. And then the actual was 9.751 10(6)m3. 543 MR. ROGERS: That's right. 544 MR. THOMPSON: So quite a swing from actual to forecast in that particular year. 545 MR. ROGERS: Yes. 546 MR. THOMPSON: And then if you quickly jump to the next year, that's December 31, 2001, that's at page 9, in line 12, your forecast was 9.663 10(6)m3, and the actual here now fell below, 8.997, 10(6)m3. 547 MR. ROGERS: That is correct. 548 MR. THOMPSON: Then we come forward to 2002, which is page 11. Your forecast, 8.693 and your actual 9.685, 10(6)m3. 549 MR. ROGERS: That's correct. 550 MR. THOMPSON: So there are some significant variations in the total contract forecasts, and obviously within the various line items that make up those forecasts. Can you help us with understanding why there are these significant swings? 551 MR. ROGERS: Yes, sir. There were four events, really, from '99 to 2002 that caused those swings and made it difficult to forecast the volumes. Number 1 was that in 1997, the nuclear units, both A units at Bruce and Pickering were removed from the system for refurbishment, and at that time we worked with Ontario Power Generation and brought on line a very large merchant cogen. Merchant plant is a better way to put it. It is a boiler, it's not a cogen. It had previously been able to burn oil, was converted to burn oil and gas, and at that time was brought into service in '98, so just prior to '99. And at that time was negotiated to be a long-term, 15-year contract, expected to run only during the highest peaks in the summer months. And so with the nukes off line, due to be back '99 to 2000, we were faced with the proposition of how to forecast that properly and fairly. 552 We forecasted it at its contractual volume to burn, which is what we were told was what we should by the customer, that it was the proper way to do it. But in fact, during '99, 2000, 2001, 2002, we can talk about -3, we can talk about -- there is a changed circumstance in 2004, but through the entire period '99 to 2003, even the current year, the nuclear units did not return. Now, we believe they will be back on, and I'll speak to that in terms of IMO 18-month forecast. But they were not on. Each year we were told they would be on. So that was the first factor that we faced. 553 The second was the Ontario electricity market opening. Again, it was due to the up and operational expected in late '99 to 2000, and once again, year by year was delayed and delayed until 2002, at which time it opened in May. And it was altered dramatically in November by the change in circumstances in the freezing of some of the rates in 2002. So once again, that market opening delay caused us dilemmas. 554 The third thing that happened during that period because of those two events was the uncertainty of the potential buy-down of our IPP-contract customers. Seven of those customers have one-year contracts, and we were told, we knew from industry reconnaissance, that they were considered high-priced, they were signed in the early '90s, when there was a concern about the inability to have enough power. With the potential return for market opening to access power from other jurisdictions and the issue of the nuclear units coming on year to year, we were faced with not knowing that we would, in fact, have contractual commitments for even the minimums in those contracts if, in fact, they were renegotiated and bought down. So we faced that. 555 The fourth thing that caused the high swings during that period of time was the volatility of the natural gas price, both high and low. In '99, we forecast our interruptible volumes and our alternate fuel market share four months in advance of the forecast period. And the challenge there was for us to be able to know what the prospective relationship would be between primarily oil and gas, but other alternate fuels as well. So as we entered each of those years we set the number at what we thought was a fair number, and when we entered the year, the gas price, since '99, has been volatile and was down in '99, down in 2000, rose in 2001, which gave to the large losses we sustained there in the industrial markets, and returned up in 2002, only to be -- sorry, went down in 2002, stayed down for the first five months of 2003, only to come back up in May of 2003, at which time it's expected to remain up for the remainder of 2003 and for all of the forecast period 2004. 556 Those four events led to the changes in the volumes for the historical period that we're looking at. And so they are primarily the existing the large merchant cogen, oil or gas-fired. The second was the IPP. The third was the impact on gas prices, mainly on alternate fuels but also on growth or negative growth, which are plant closures and other events. 557 MR. THOMPSON: Thanks for that. I'll come back to a couple of those in a second. Just to complete the picture here, the forecast for 2003 was, what? We know that you're currently expecting 9,260, 10(6)m3. What was the forecast? Is that in the record somewhere? 558 MR. ROGERS: That is an updated number. I don't remember us ever putting in an original 2003 white-page forecast. 559 MR. THOMPSON: Again, I couldn't find it. Could we have that number? Could you produce that by way of undertaking? 560 MR. ROGERS: I believe we can. I just -- I noticed during the evidentiary review that I wouldn't find it either in the evidence. 561 MR. THOMPSON: Don't you -- 562 MR. ROGERS: Hold on. I just know that it isn't here. It wasn't that we were not willing to give it. We may have it. 563 Yes, if I could refer to Exhibit C.4, tab 2, schedule 1. 564 MR. SOMMERVILLE: Sorry, can I have that reference, Mr. Rogers? 565 MR. ROGERS: Sorry. Exhibit C.4, tab 2, and schedule 1. 566 MR. SOMMERVILLE: Thank you. 567 MR. THOMPSON: Is this, then, the white sheet that you're going to refer to? 568 MR. ROGERS: That's correct. The number that we would take from that that would compare with the blue-page update is in line 20, the total contract number of -- I could quote it if you like. 569 MR. THOMPSON: 9,282, approximately, 10(6)m3. 570 MR. ROGERS: That's correct. 571 MR. THOMPSON: So your expectations are about 52, 10(6)m3, below forecast. 572 MR. ROGERS: That's correct. 573 MR. THOMPSON: That's not as significant a variance as you had in prior years. 574 MR. ROGERS: No. It reflects -- no. That's correct. 575 MR. THOMPSON: Now, I don't know if you can provide this for me on the record, but I would like to have the company put on the record, if it could by way of undertaking, the impact on the revenue deficiency of a 100, 10(6)m3 adjustment to the estimates that have been made, and in two scenarios; one without a change in contract demand and a second with a change in contract demand. Unless someone has that now and put it on the record. Otherwise, could I have an undertaking. 576 MR. ROGERS: I'll take an undertaking. 577 MR. MORAN: Mr. Chair, that will become undertaking N.4.2. 578 UNDERTAKING NO. N.4.2: TO PROVIDE A SENSITIVITY OF THE REVENUE DEFICIENCY TO A 100 10(6)m3 UNDERESTIMATE OF CONTRACT DEMAND USING TWO SCENARIOS; ASSUMING THE CDS DO NOT DECREASE OR WITH A CHANGE IN THE CONTRACT DEMAND; FURTHER, TO PERFORM SENSITIVITY ANALYSIS FOR M17 FIRM AND R25, SPECIFYING IF AVERAGE IS WEIGHTED OR NOT 579 MR. SOMMERVILLE: Could you just reiterate the undertaking, Mr. Thompson. 580 MR. THOMPSON: Yes. It's to get a sensitivity, if you will, of the revenue deficiency to a 100, 10(6)m3, underestimate of contract demand. It's in two scenarios, assuming the CDs do not decrease, so it's just further higher load-factor consumption by existing contracts, customers under the auspices of their contracts, or with a change in the contract demand, which would add more revenue. 581 MR. SOMMERVILLE: Thank you. 582 MR. THOMPSON: So that's M.4.2? Thanks. N.4.2. 583 Now, just at a high level, Mr. Rogers, the numbers indicate there is this potential for significant variance, and we all, on the ratepayers' side here, know that there's this tendency to understate forecasts on the occasion of rate rebasing in a cost-of-service regime. 584 I don't want to get into, in great detail, the extent to which numbers have varied over the years, but is there some mechanism that you would suggest that would enable ratepayers to have confidence in these forecasts? I'm thinking if the actuals turn to be significantly out of whack with the forecasts as the year progresses, that there's some adjustment to the charges that are made in -- recovered in rates. Has any thought been given to that kind of mechanism? 585 MR. ROGERS: I haven't -- I haven't given that specific thought. But if we refer to Exhibit -- my evidence, Exhibit C.1, tab 2, page 10 of 12. And the explanation there that I give from line 16 to 22, basically what we have is a sustainable change in circumstances from prior years. Three things are going to happen this year that didn't happen in prior years. One is we believe, and the IMO 18-month forecasts firmly support this, the last three of May -- April, May -- 586 MR. PENNY: Sorry, Mr. Rogers, could you stay closer to the microphone. 587 MR. ROGERS: Sorry. Supporting the 18-month IMO forecast that, in fact, there will be 2,040 megawatts of nuclear power back on-line in 2004. That's at the two plants at the Bruce A and one unit from Pickering. So that's a significant change. 588 The second one is the fact that we have built into the forecast, and it's reflected in line 19 of my evidence on that page 10 of 12, tab 2, C.1, that we have increased our forecast by 1068, 10(6)m3, which is because of three new gas-fired merchant plants that are on-line, or will be on-line by the forecast period. So if you add the two of those up, there will be 3,260 megawatts of either nuclear power, which will be high efficiency, low priced, and 1,220 megawatts of new high-efficiency merchant power plants which will displace the existing oil/gas-fired lower-efficiency merchant power plant that we've had in the past, and, in fact, will replace or push the independent power producers that I mentioned before down to their contract minimum usage for the period. 589 So those two things, I believe, will dramatically narrow the variability of the forecast going forward, because with the nuclear units back and the more high-efficiently merchant power plants which we have forecasted in place, we believe that we are going to eliminate that 952 of existing peaking facilities and independent power plants at the top, above their contractual burn. What we have not reflected here, which we think is risky, is that those IPP plants could, in fact, be restructured under a financial review. And if they are, we have the forecasts -- in the forecast numbers that support them. 590 The other thing for 2004 is that we are on a trend since May of 2003, and I've mentioned this before, of high gas prices. The prices are up and they are expected to stay up. We've reflected that impact on our 2-03 blue actuals and have adjusted the 2-04 because of that in our blue-page update. Those -- we can't control the gas price, but we believe it will stay up. We can't control the nuclear units or the -- but we know they are going to be back on. So those changes, we believe, are going to narrow the band width significantly, and the impacts, going forward, will be back into what I will call a more normal range of the factors that I have on the bottom, 21 and 22, pardon me, which are efficiency, alternate fuel market share, and net growth, which is the add of new loads and the loss due to plant closures. And due to the high gas prices, what we've reflected here in the blue-page update is that trend for alternate fuel market share to be down and for the impacts of plant closures to be worse than the growth -- the net growth that we would get from acts. 591 So for those reasons, we think that the issues of the past, mainly driven by uncontrollable circumstances on the power market, will be -- have been corrected because we now have the newer merchant plants in the forecast, and we will have to do our best to forecast the impacts of gas pricing as it goes up or down. 592 MR. THOMPSON: Are there any circumstances in this what you call uncontrollable circumstances of the power market that could emerge that would cause this forecast to be materially low for 2004? 593 MR. ROGERS: I don't believe so, because we've already taken the full impact of the three new plants and added in the 1,068 10(6)m3. So they are firm loads, they are committed, and we believe that that will displace the other two, both the existing oil and gas merchant plant and the other IPP loads. 594 MR. THOMPSON: Are there any circumstances, and if so what are they, that could cause this forecast to be materially low unrelated to the power market? 595 MR. ROGERS: If the gas price deteriorated over the contract period, unlike we believe it will and what all our forecasting information says it will do, that could have an impact because, if gas prices were to come down, that would, in our opinion, probably cause an increase in an alternate fuel market share capability for gas. That's the one that I truly believe would have an impact. So we're in the hands of the relationship of gas and other fuels. Plus, not only the retention of alternate fuel, but the impacts of high gas prices driving higher efficiencies and plant closures, which we've reflected in this forecast. 596 MR. THOMPSON: And is there some relationship, correlation, between the gas prices and contract volume through-put? In other words, if price dropped X cents, does through-put go up in some sort of measurable amount? 597 MR. ROGERS: If I could find the reference, I think there is an interrogatory response that helps us with the answer to that. Exhibit -- I'd like to refer to Exhibit J.1.56. This is an answer to an interrogatory from Board Staff. In terms of the alternate fuel relationship, this answer, I believe, illustrates our point. 598 What I'd like to refer to is column C, which is the percentage market share of gas versus alternate fuel in our highly fuel-switchable loads. If we look at 2001, which is the year that we were underforecasted dramatically, or we underperformed the forecast, Union, on the contract accounts, the percentage market share was 56 percent. And what I can do, it is in the evidence, so if we were to fill this out now for -- going forward, we would see that in our 2-03 blue-page update, we are predicting 61 percent, reflecting the turndown in gas pricing for the last six months of 2-03, and in fact we are predicting, as per the blue-page evidence, for 2-04 blue, a 58 percent market share. So the 58 for next year, the 61 for this year correlates closely to the 2-01 data and we don't have a model, unlike the regular rate market, it's a little tougher with the contract markets because they are pretty unique as opposed to homogeneous, but this, I believe, illustrates the point behind the forecast that we have created. 599 MR. THOMPSON: Okay. So if it comes decision time, the market price for natural gas for 2004 is expected to be considerably lower, what sort of adjustments should the Board be making in terms of through-put estimates of the contract volumes? 600 MR. ROGERS: I can't answer that because we believe that the gas price will stay where it is and will reflect the same conditions as 2-01. We are into that for 2-03 and expected to sustain itself that for 2-04. If you told me a pricing relationship for gas, we could probably fit it back into here and come up with one of -- with an estimate. But it would be -- this, we believe, illustrates our point. 601 MR. THOMPSON: All right. I'll leave it there. 602 Can I move, just for a few moments, and this is my last area, to the S&T revenues. That's you, Mr. Poredos? 603 MR. POREDOS: Yes, it is. 604 MR. THOMPSON: Mr. Warren referred you to -- perhaps I can just start here with Exhibit C.1, tab 3, appendix A. Let me make sure I understand what those dollars represent. 605 MR. POREDOS: Yes, I believe I have that. 606 MR. THOMPSON: All right. That table is entitled the "Summary of Deferrable Revenue by Deferral Account." So that is the amount that you're estimating will be posted to the S&T deferral account in 2004; is that right? 607 MR. POREDOS: That's correct. 608 MR. THOMPSON: Okay. And I understand from your testimony, Exhibit C.1, tab 3, page 12 -- 609 MR. POREDOS: Sorry, Mr. Thompson. Page 3 -- 610 MR. THOMPSON: C.1, tab 3, page 12. This is the blue sheets, the updated. 611 MR. POREDOS: The updated. It's on page 3 of 12? 612 MR. THOMPSON: Yes. You tell us in line 6 to 8 that the table at C.1, tab 3, appendix A, reflects the updates to the forecast and shows the deferral revenue above the threshold level of 5.5 million. Is that right? 613 MR. POREDOS: That's correct. The 5.5, or the 5 million, as we had talked about with Mr. Warren, is in rates. These reflect margins above that that would be deferred. 614 MR. THOMPSON: And so if the Board were to subscribe to the view of intervenors that the forecast deferrals above that current threshold should be embedded in rate, or alternatively the threshold should be -- another way of saying the same thing is you move the threshold embedded in rates up, does the 2.761 represent only the ratepayers share of revenues, or does that include the 25 percent share that shareholders would get under the current sharing regime? 615 MR. POREDOS: That number is prior to the 25/75 split. 616 MR. THOMPSON: So if the threshold moved up, as we've suggested, and the 75 percent sharing remained as is, that would put about 15 million of this amount into rates; correct? 617 MR. POREDOS: Subject to your calculation, I think you're correct. 618 MR. THOMPSON: I just took three-quarters of 20. Stated another way, it would reduce the revenue deficiency by about $15 million. 619 MR. POREDOS: I believe so. 620 MR. THOMPSON: Okay. Now, your Exhibit C.1, tab 3, appendix A shows the various components of this total of 20,761,000, and the biggest component is long-term market premium; right? 621 MR. POREDOS: Yes, that's correct. 622 MR. THOMPSON: And that relates to, as I understand it, contracts -- well, you tell me. What does that relate to? 623 MR. POREDOS: That relates to the assumptions we make that the M12 contracts, when they renew, will in fact be renewing at the C1 or market rates. So there would be a differently, which is the market premium, between what we could achieve and what's embedded in costs for the M12 rate, the cost-base rate. 624 MR. THOMPSON: But some of these contracts, as I understand, have already renewed at market rates. 625 MR. POREDOS: Some have, yes, that's correct. 626 MR. THOMPSON: And these are -- well, are they long-term -- they must be long-term contracts. 627 MR. POREDOS: Those are long-term contracts. But again, Mr. Thompson, it's an assumption on our part that those contracts will renew as long-term contracts. There's no guarantee that a customer may want to decide that they want to go for one year and go for a short-term contract. There's no guarantee that the customer may not decide to portfolio those contracts. There's no guarantee that they may not go to a third party to buy an equivalent contract or amount at a different rate. So it's not an issue of guarantees. 628 MR. THOMPSON: No, there are no guarantees in life. But when it comes to forecasts and they relate to costs, your company is very confident that they're going to materialize, not only when we talk about revenues, we hear that cautions, the never-ending cautions about being them realized. What I was trying to nail down was -- that's just a preamble. 629 MR. PENNY: A rhetorical preamble. 630 MR. THOMPSON: How much has already renewed? Some of these long-term premiums, like GMI renewed, for example, a few years ago. 631 MR. POREDOS: GMI renewed, in fact, about 5.9 pJs this year. Of the total contracts we hold for ex-franchise storage, about 50 pJs of that has been renewed. There is another 24 pJs that will be up for renewal in 2004. 632 MR. THOMPSON: All right. And these are contracts with other distributors, are they? 633 MR. POREDOS: They may be. They're with other utilities. It may be a customer who wants to have a guarantee of availability of storage into the future. There are various customers in that mix. 634 MR. THOMPSON: All right. Now, you said to Mr. Warren, I just want to get some clarification on this, that you had a reluctance to embed the forecast in rates because you thought that increased shareholder risk, something to that effect. 635 MR. POREDOS: To my understanding of what Mr. Warren asked is that if the Board was to decide to put the -- that amount, the 20 million, into rates, what would be the impact from Union's standpoint. That would basically suggest that the 20 million is guaranteed in rates and we would have to take the downside risk. If we could not achieve that $20 million in S&T transactions, the shareholder would take the whole risk. There is no downside sharing from the customer standpoint. 636 MR. THOMPSON: If there was some downside sharing, would that alleviate your concerns? Our concern is you're going to have $20 million sitting on the sidelines. Why shouldn't it be in rates? 637 MR. POREDOS: Mr. Thompson, the reason for the deferral account is exactly the reason you're asking for. If there was some sharing, that's what the deferral account will do. The deferral account allows those revenues to go through the deferral account and be appropriately shared both on the up and downside. That's the reason for the deferral. So Union has recommended that that continue as we go forward. 638 MR. THOMPSON: Well, I'll argue the embedding aspect of your proposition. But is sharing on the table here as an issue, as far as Union is concerned? For example, the last time this issue was adjudicated with respect to sharing, I think the ratepayers got all of the long-term market premium, or most of it. 639 MR. POREDOS: I believe you're correct, Mr. Thompson, for 2000. However, if I remember correctly, in 0017, going into 2001, the Board made the decision that, in fact, those should also be shared at 75/25. The Board, on several occasions, had said that providing an incentive to Union through the sharing of the premium and -- on the transactional sales for S&T is appropriate, and they support it because of the opportunities that the utility should pursue and make -- and make sure that the assets are managed efficiently. 640 The Board, in 0017, suggested that the Board recognizes there should also be an incentive to effectively manage the existing storage capacity in Ontario. The decision suggested that, providing the company financial incentives to maximize revenues for these services should increase benefits to both the customer and the shareholder. And Union agrees with that position. And our position, going forward, with the deferral account and the forecast we've made, supports that, I believe. It is for the good of customers and the shareholder. 641 MR. THOMPSON: Well, let me just take you to one question, one interrogatory response, just again to get the numbers on the table. This is one of Mr. Aiken's interrogatories, Exhibit J.18.199, supplemental. 642 MR. POREDOS: Yes. I have that, Mr. Thompson. 643 MR. THOMPSON: He's asking you to, in effect, apply what you've described as the EBRO 499 methodology, and you've mentioned it was changed subsequently and approved by the Board. That was another decision, was it, following EBRO 499 where you say the Board endorsed the 75/25 overall sharing? 644 MR. POREDOS: Yes. 645 MR. THOMPSON: I see. Was that based on a one-year agreement with ratepayers, or was it an adjudicated matter, or can you recall? 646 MR. PENNY: That was the matter that Mr. Poredos was just referring to, the matter RP-1999-0017 which was adjudicated. 647 MR. THOMPSON: All right. Thank you. Do you accept the -- well, these numbers appear to indicate that if you subscribe to the -- to the -- well, tell me what they indicate. If you subscribe to the EBRO 499 sharing, the amount that would go to ratepayers, assuming the $20,761,000 forecast is correct, it's more than the 15 million we were discussing. It would be a larger number. 648 MR. POREDOS: I'm sorry, Mr. Thompson, the question was to explain what's in that IR or -- 649 MR. THOMPSON: Well, is this answer telling me that if we subscribe to the 499 sharing regime, that the ratepayer would get not the 75 percent of 20 million 761, but 75 percent of 20 million 761 plus $3,114,000. Is that your understanding of the response? So the ratepayer -- 650 MR. POREDOS: What the question was, I believe, if I remember, as we work through this, the question wanted us to use the original 499 split of 90/10 on the basis of the 2004 forecast. Our original evidence assumed that the threshold forecast or the base forecast was the same as 499, which was the $5 million embedded in rates. Now, I believe the question asked to take the forecast we had at the time, then, and apply it at the 90/10 split. 651 MR. THOMPSON: So this is embedded 90 percent of the forecast in rates. 652 MR. POREDOS: That's correct. That is not what Union is proposing, however. 653 MR. THOMPSON: No, no, I understand you're not in favour of that. All right. 654 Thank you. Those are my questions, Mr. Chairman. 655 I'm most appreciative for being allowed to proceed. 656 MR. SOMMERVILLE: I beg your pardon. I didn't hear your -- 657 MR. THOMPSON: I'm most appreciative of being allowed to proceed out of order. 658 MR. SOMMERVILLE: Okay. It's now a quarter to one. 659 MR. JANIGAN: Mr. Chairman, for the benefit of anybody who was listening on the record, we set priorities by those that had to leave today rather than those who want to leave today. I would have been overwhelmed if the latter category had been chosen. In that respect, Union and OPG will be proceeding with their cross-examination this afternoon, and I expect I will be started but not get finished. Sorry, Kitchener. Kitchener and OPG will be proceeding. 660 MR. PENNY: I was worried that I haven't prepared my cross-examination yet. I might need more time. 661 MR. SOMMERVILLE: In light of Mr. Rogers' testimony. 662 Mr. Ryder, then, you are next. 663 MR. RYDER: Yes, sir. 664 MR. SOMMERVILLE: Are you prepared to proceed now, or would it be possibly more convenient to start after the break? 665 MR. RYDER: I'm totally in your hands, sir. 666 MR. SOMMERVILLE: Why don't we break now and reconvene at ten minutes to two. Thank you. 667 --- Luncheon recess taken at 12:50 p.m. 668 --- On resuming at 1:51 p.m. 669 MR. SOMMERVILLE: Please be seated. Thank you. 670 Mr. Ryder? 671 CROSS-EXAMINATION BY MR. RYDER: 672 MR. RYDER: Panel, I act for the City of Kitchener, and Mr. Quinn is with me, who is the director of utilities there. Kitchener is the only customer in the T3 class? 673 MR. ROGERS: Yes, it is. 674 MR. RYDER: And in the last main rate case of EBRO 439, Kitchener was part of the M9 class? 675 MR. ROGERS: That's correct. 676 MR. RYDER: And then it moved into the T3 class for the year 2000? 677 MR. ROGERS: Yes, because the five-year contract ends April 2003. That's correct. 678 MR. RYDER: And the white-page forecast for the T3 class is at C3, tab 2, schedule 1, and it comes to 286,761, 10(6)m3. 679 MR. ROGERS: Sorry, Mr. Ryder, I'm just pulling that up. Yes, the white page for the test year 2-04 is 286,761, yes. 680 MR. RYDER: And for the blue-page forecast, it's the same? 681 MR. ROGERS: That's correct. 682 MR. RYDER: And the blue-page, generally speaking, incorporates five months of actual and seven months forecast? 683 MR. ROGERS: That's correct. 684 MR. RYDER: And one reason why there was no change in the blue-page forecast for T3 is that you don't normalize T3 volumes when forecasting. 685 MR. ROGERS: Neither T3, nor M9, that's correct. 686 MR. RYDER: And can you tell me what classes are normalized for forecasting purposes? 687 MR. ROGERS: None of the contract classes that I'm responsible for are. My colleague maybe could answer on behalf of the regular rate market. 688 MR. GARDINER: With reference to the same exhibit, C.3, tab 2, schedule 1, rates N2, 01, and 10 are weather normalized. 689 MR. RYDER: And why is that, sir? 690 MR. GARDINER: Because those are general service classes with lots of customers within the rate class, and by "lots" I mean, an example, rate M2 has over 800,000; rate 10 has 2,875 customers, that's still a large number. And they have an identified consumption weather relationship. 691 MR. RYDER: So they're heat-sensitive customers? 692 MR. GARDINER: That is correct. 693 MR. RYDER: Now, Mr. Rogers, is there any component in the T3 volumes that's heat sensitive? 694 MR. ROGERS: I would think so, as the City of Kitchener serves a high residential base load and commercial industrial, what I would call the CI markets in Union, which is the smaller contract markets. 695 MR. RYDER: Do you know how much of Kitchener's T3 volumes are heat-sensitive? 696 MR. ROGERS: I don't. 697 MR. RYDER: Why wouldn't you know that? Wouldn't you need to know that in order to assess its -- to make your forecast? 698 MR. ROGERS: No, not really, because it's similar to other semi-unbundled T1 rate class. We do not weather normalize that either. That is because we have no responsibility for the balancing. T3 and T1 customers have to balance daily. So unlike a bundled service where are responsible for and need to have the gas and other assets available to us to allow that to happen, the T1 and T3 balance daily. 699 MR. RYDER: But the T1 is not a weather-sensitive load, I mean, to the degree that residential customers are? 700 MR. ROGERS: Generally, it's a higher load factor and that's basically the difference between a T1 and the single T3 customer, is the load factor. 701 MR. RYDER: Yes. But T1 is not comprised of heat-sensitive customers. 702 MR. ROGERS: Typically not. 703 MR. RYDER: No. I thought they were entirely industrial customers. 704 MR. ROGERS: They are. They come from, generally, the M7 rate class, which is the very large industrial and the M4/5. 705 MR. RYDER: Now, I should perhaps ask you, is a normalization a requirement in the forecasting of your heat-sensitive customers? 706 MR. GARDINER: Could you repeat that? 707 MR. RYDER: Is normalization a requirement to properly forecast the volumes consumed by your heat-sensitive customers? 708 MR. GARDINER: In the general service market, yes. 709 MR. RYDER: And, Mr. Rogers, if you introduced the practice of normalizing the heat-sensitive T3 volumes, if you introduced that practice into your forecasting method for T3, would that not tend to improve the accuracy of your forecast? 710 MR. ROGERS: I really don't -- I don't know. That's a good question. We have other smaller customers in the commercial and industrial that are in the M4 bundle class that we don't heat-correct or normalize, is the word I'm looking for. So I'm not sure whether normalizing would improve the forecasting or not. 711 MR. RYDER: Well, let's look at the method that you did employ to forecast the T3 and that's set out in J.5.24. Can you look at that, please. 712 MR. ROGERS: Yeah. 713 MR. RYDER: Paragraph C. 714 MR. ROGERS: Yes, I have it now. 715 MR. RYDER: All right. Now, just to summarize, I read that you relied on actual consumptions for the three years between 2000 and 2002, that was your first step, and then you averaged that, those three years, and then you added 1 percent on top of that for growth. 716 MR. ROGERS: That's right. 717 MR. RYDER: Why did you add the 1 percent? What was the basis for that? 718 MR. ROGERS: That was the trend that had been consistent for CCK over the last period of time. We looked at the two years and looked back over a period of five years, and on average it was 1 percent. 719 MR. RYDER: So is the trend 1 percent per year? 720 MR. ROGERS: On average. 721 MR. RYDER: And that's not weather normalized? 722 MR. ROGERS: No. That just takes into the account that Kitchener, like Union, would have growth in its residential markets and other markets, and the net growth -- this is the net growth figure of 1 percent. 723 MR. RYDER: Per year. 724 MR. ROGERS: Per year, yeah. 725 MR. RYDER: Now, if you applied the 1 percent increase to the average of three years, that's not 1 percent per year, is it? 726 MR. ROGERS: Could you say that again, sorry. 727 MR. RYDER: If you applied the 1 percent to your average of -- to your three-year average, you're not incorporating a 1 percent per year growth, you're really incorporating a third of a percent per year. 728 MR. ROGERS: I'm just trying to think it through. You're saying that instead of the actual numbers, a 1 percent lift -- well, if you take the three numbers and average them out, then the 1 percent per year growth of those three would be less than a 1 percent, assuming that each of the years grew, yes. 729 MR. RYDER: So it's under the trend that you've identified of a 1 percent per year growth. 730 MR. ROGERS: 1 percent over the average, so that's what we used, using your methodology. 731 MR. RYDER: Could you reproduce your forecast using the same three years but using normalized volumes? 732 MR. ROGERS: Sorry, sir, could you repeat the question? 733 MR. RYDER: I'd like you to reproduce your forecasts using the same three years of 2000 to 2002, using normalized volumes. 734 MR. ROGERS: I don't know the basis under which we would normalize Kitchener. Unless you have -- unless your entire market -- unless Kitchener's entire market was residential or the general service equivalent to what we do for Mr. Gardiner, I have no methodology that would incorporate any industrials or any other mix of customers under the Kitchener area. And the issue I have in trying to do that is, once again, we don't weather normalize any large contract customers, which Kitchener certainly is. 735 MR. RYDER: So the reason you can't do it because you don't know the percentage of Kitchener's volumes that are heat-sensitive. 736 MR. ROGERS: I'd say that's correct. We don't know how many residential and how many commercial. We don't manage that on behalf of Kitchener. 737 MR. RYDER: And if you knew the amount of Kitchener's volumes that were heat-sensitive, you could normalize that component? 738 MR. ROGERS: I'm not sure that we would adopt that practice. For instance, Kitchener -- or Enbridge and Kingston, which are both customers of ours that have a mix of customers similar, although Enbridge is much larger, perhaps Kingston is a better analogy, are on ex-franchise, I believe they're M12 rates, and we do not weather-normalize them because, in fact, they don't -- we just don't because it's a wholesale customer purchase. 739 MR. RYDER: Well, Kitchener is not an M12 customer. 740 MR. ROGERS: No, I know that. I'm drawing an analogy to someone who we don't weather-normalize who is a customer of ours who has a mix of residential, commercial, industrial. 741 MR. RYDER: Well, could you, nevertheless, assume that 80 percent of Kitchener's load is heat-sensitive, normalize that for the three years of 2000 to 2002 and reproduce your forecast? 742 MR. ROGERS: We could take an undertaking to -- let me just state what I think you're asking, sir. It would be to use our methodology for the residential market. Now, we do weather-normalize some of the small commercial/industrial. That's the only factor I would add into there is that there is weather normalization through all of the general service market. But if we applied that same model to a number totaling 80 percent of Kitchener's volume, I would think we could do it. 743 Paul, I'm going to ask Mr. Gardiner is that is -- if we take an undertaking, is it a doable undertaking. 744 MR. GARDINER: I think it is doable. There are two alternatives. One is to -- sorry. I'm sorry, there are two alternatives. One is we could use, as Mr. Rogers mentioned, we could use the weather elasticities from the general service market on a combined basis and apply it to the City of Kitchener 80 percent of the volumes. That would be the easier way. 745 A longer period analysis would be we'd have to take -- I'd have to look at all the monthly weather and volumes and do the analysis that way, and that would take more time. 746 MR. RYDER: How much more time? 747 MR. GARDINER: How much more time? 748 MR. RYDER: Is it still a reasonable request? I mean my client would prefer the latter, if that can be done without undue difficulty. 749 MR. GARDINER: We could do it for next week. 750 MR. RYDER: That would be much appreciated. 751 MR. MORAN: Mr. Chair, that would be Undertaking N.4.3. I wonder, for purposes of the record, if Mr. Ryder could restate the undertaking. 752 MR. RYDER: It's the second undertaking that Mr. Gardiner described, which is the long-term forecasting -- you describe the second undertaking, could you. 753 MR. GARDINER: The second undertaking would be for rate T3, take the monthly volumes for rate T3 over the last number of years, and that might be an issue, and I may need some assistance from CCK to ensure that I have all the proper volumes, and then correlate that to the heating degree day statistics, and I would use Union Gas south heating degree days, which are readily available, and then do the regression analysis on that. 754 MR. RYDER: So I think as a description of the undertaking, you'll reproduce your forecast for the T3 2004, normalizing a portion of its load. 755 MR. GARDINER: Correct. 756 UNDERTAKING NO. N.4.3: TO REPRODUCE FORECAST FOR THE T3 2004, NORMALIZING A PORTION OF ITS LOAD 757 MR. ROGERS: I'm just going to ask Mr. Gardiner if you're implicitly clear on what you're going to do. 758 MR. GARDINER: Yes. 759 MR. ROGERS: Good. 760 MR. RYDER: Now, from the white page to the blue page, did you alter the forecast for the M9 class? 761 MR. ROGERS: Sorry, Mr. Ryder, could you repeat that. 762 MR. RYDER: From your white-page forecast to your blue-page forecast, did you alter the forecast for the M9 class? 763 MR. ROGERS: Let me just turn to that. No, we did not. 764 MR. RYDER: All right. And is that because you don't denormalize their volumes? 765 MR. ROGERS: That's correct. 766 MR. RYDER: All right. Now, Mr. Gardiner, does your information about the weather in Kitchener support the suggestion that it's colder than your average franchise weather? 767 MR. GARDINER: The average Union Gas heating degree days is a combination of Windsor, London, and Hamilton in the south, and it's probably very much -- very close to London. There is some difference because it's an average of those three. I haven't got on hand City of Kitchener weather data, but I would -- but I know from the correlations of Windsor, London, and Hamilton with Pearson that they're 99 percent correlated, so I would expect that Kitchener and Union south would be highly correlated. That's why, for the sake of responding, I would like to use Union south heating degree days, and it would assist the process. 768 MR. RYDER: My information is that Kitchener is roughly 8 degrees -- 8 percent, sorry, cooler. 769 MR. GARDINER: Yes. But through the correlations, what would happen, if I had the City of Kitchener weather, what would happen is the weather coefficient for each month between the volume and the heating degree day would adjust. So if you use Union south for January, you might have a number like, for every heating degree day, 100,000; if you use City of Kitchener and it's 8 percent colder, it will say, you know, 92,000. Because of the correlation, what will happen is the weather coefficient will calibrate to that. 770 So I recognize that, you know, it's a little further north, but I think the -- what's being asked, Union south data would be -- would work. 771 MR. RYDER: Thank you. Now, the blue-page update for volumes takes into account data for 2003, does it not? 772 MR. ROGERS: Five and seven, yes. 773 MR. RYDER: Five and seven. And could I ask you, then, to reproduce your forecast for the T3 using -- the way you did it, using the three years of 2001 to 2003 instead of 2000 to 2002? 774 MR. ROGERS: I don't see why not. 775 MR. RYDER: Thank you. Would that be N.4.4? 776 MR. MORAN: N.4.4, Mr. Chair. 777 MR. PENNY: As long as Mr. Ryder understands that because 2003 isn't over yet, that that will include a forecast. 778 MR. RYDER: Yes, six months. 779 UNDERTAKING NO. N.4.4: TO REPRODUCE FORECAST FOR THE T3 USING THE THREE YEARS OF 2001 TO 2003 INSTEAD OF 2000 TO 2002 780 MR. RYDER: I handed out earlier to your counsel and Mr. Reghelini Exhibit J.31.G2.57 of EBRO 499. Do you have that? 781 MR. ROGERS: I do not. I don't have that. 782 MR. RYDER: Well, it's not important. I was just using it to obtain from you the Kitchener forecast that was used in EBRO 499. 783 MR. ROGERS: I really can't answer if I don't have the document. 784 MR. RYDER: Can you produce that, then, for me as an undertaking? 785 MR. PENNY: Well, do you have it with you? Why should we go out and engage in some burdensome search for something that you've got right in front of you? 786 MR. RYDER: Take it easy. I delivered it to your group there a couple of days ago. 787 MR. MORAN: Mr. Chair, perhaps we can mark this as an exhibit. It will become Exhibit M.4.1, a document entitled "Exhibit J.31.G2.57 from EBRO 499." 788 EXHIBIT NO. M.4.1: EXHIBIT J.31.G2.57 FROM EBRO 499 789 MR. PENNY: When this was given to us, Mr. Chairman, it had written across the top that it was from Kitchener -- from Mr. Ryder that it was for the gas supply panel -- storage allocation, excuse me, which is why it wasn't taken up with this group. 790 MR. ROGERS: The people that answered this are -- I don't have responsibility for this. 791 MR. RYDER: Well, it shows, if I can take you to page 2, Kitchener is customer A? 792 MR. ROGERS: Yeah, I see it. 793 MR. RYDER: And the volume there opposite annual volume forecast C '99, the volume is 296,501 10(6)m3. 794 MR. ROGERS: I see the number. 795 MR. RYDER: All right. Can you just confirm whether that's correct or not? 796 MR. ROGERS: Not without -- I really don't know without looking. 797 MR. RYDER: Can you take an undertaking to do that? 798 MR. PENNY: Just a moment. If we have witnesses that are coming up on a subsequent panel who will be able to answer the question, then in my submission, Mr. Chairman, it doesn't make any sense to burden this panel with additional undertakings. 799 MR. RYDER: Well, Mr. Rogers, it looks very likely that this is a document produced by Union in a prior case. 800 MR. ROGERS: But the people on there were for the rate allocations group, and so I don't have responsibility for that. 801 MR. RYDER: But this is allocation that is based on the annual volume forecast? 802 MR. ROGERS: That is correct. 803 MR. RYDER: Yes. And so subject to check, surely you could assume for the purposes of my questioning that the forecast for calendar 1999 was 296,501, 10(6)m3. 804 MR. PENNY: I think we are prepared to assume that for the purposes of your question. That wasn't your question. 805 MR. ROGERS: I'm just referring to the information in J.17.15 from this case, and we do go back to a number that has M9 as a class. So the only data I have that I can refer to that I'm prepared -- that I have, is on that J.17.15, and for the Board-approved number for 1999, for the wholesale group, was 323,049, which does not correlate with the total rate class D on your exhibit from 499 of 319,699. So the data I have does not correlate so I really can't draw the conclusion here on the stand. So I don't know any other way to check this but to take it as an undertaking and take it away. 806 MR. RYDER: All right, thank you. 807 MR. MORAN: Mr. Chair, I'm not sure if I understand what the actual undertaking is. 808 MR. PENNY: Mr. Chairman, my point stands that if there are witnesses -- 809 MR. SOMMERVILLE: It seems to me, Mr. Ryder, that the way through this dilemma is simply to -- as I think you have, ask the witness to make the assumption that this number is accurate. 810 MR. RYDER: Yes. 811 MR. SOMMERVILLE: And that if a correction of some kind emerges either through your questioning of the gas supply panel or in some other way, we can revisit this. But it seems to me, simply, can the witness assume that this is accurate and we can go from there. 812 MR. RYDER: All right. I'll do that. Thank you, sir. But I'd like to ask Mr. Rogers in addition, were you responsible for the volume forecast of the M9s in EBRO 499? 813 MR. ROGERS: Not when this document was created in September of '98. 814 MR. RYDER: And are you responsible now for the forecast of the T3 volume? 815 MR. ROGERS: I am. 816 MR. RYDER: All right. And the last time the T3 volume was approved -- the Kitchener volume, a volume attributable to Kitchener was approved by the Board was in EBRO 499? 817 MR. ROGERS: Again, I would refer you to J.17.15, and the number that was attributable to Kitchener at that time, the forecast was under the M9 class, because the rate T3 volume for the forecast was zero, so that it was an M9, not a T3. 818 MR. RYDER: And is that board-approved volumes? 819 MR. ROGERS: Yes. 820 MR. RYDER: And what was it? 821 MR. ROGERS: Well, quite frankly, I don't have the breakdown. I have the M9 as a class. That's where we drew that analogy, the 319,699 from the J.31.G2.57 versus this number. My point is there was no T3 for Kitchener in the 1999 Board-approved forecast. It was an M9, not a T3. It became a T3 partway through the year, according to the actuals, and was a split report between 1999 and 2000. 822 MR. RYDER: All right. Well, taking the number in Exhibit M.4.1 of 296,501 attributable to Kitchener for calendar 1999 -- 823 MR. ROGERS: Sorry, what are you referring to, sir? 824 MR. RYDER: The number that I think you've agreed that you could take, subject to check, of 296,501. 825 MR. ROGERS: Got it. 826 MR. RYDER: All right? 827 MR. ROGERS: Yes. 828 MR. RYDER: Kitchener's forecast for the -- sorry, the Kitchener forecast for Union in 1999? 829 MR. ROGERS: Yes. 830 MR. RYDER: Now, that's about 10,000 10(3)m3 higher than your current forecast -- 831 MR. ROGERS: Okay. 832 MR. RYDER: -- five years later. Does that suggest some flaw in your forecasting approach? 833 MR. ROGERS: I didn't forecast this so all I can talk to is now. I'd have to take an undertaking back to the people that forecast this at the time and review it. 834 MR. RYDER: Can you give any explanation as to why a difference of that magnitude would appear on the downside over five years? 835 MR. ROGERS: Only -- excuse me. My colleague points out -- Mr. Gardiner points out that we really don't know what's going on within the confines of the City of Kitchener, if there have been energy efficiencies, loss of major contract loads. I know that's how we track our volumes. And again, because it is not just a pure residential load, there may have been a number of things happening that -- in 1999, that are different than 2003 or '04. So, sorry, I can't really tell you the difference between them unless you can produce that data and the variance explanations for it. 836 MR. RYDER: Well, if you can look at J.5.23, please. 837 MR. ROGERS: J.5.23? 838 MR. RYDER: Yes. 839 MR. ROGERS: I have it now. 840 MR. RYDER: That was a reference to your evidence in C.1, tab 1, page 3, where you said that each contract customer was contacted by an assigned Union sales representative to discuss the customer's business outlook? 841 MR. ROGERS: Yes. And that reference, which is on page 2 of 12, my Exhibit C.1, tab 2, page 2 of 12, basically -- I'm sorry, the page 3 of 12 is where I made the reference, and page 2 of 12, the group of 76 customers in line 1 on page 2 of 12 were the customer group that I was speaking to, which is the largest, and I should have said industrial customers, which are the M7, T1, and rate 100 accounts. 842 MR. RYDER: So that reference refers to your largest industrial customers. 843 MR. ROGERS: Yes. 844 MR. RYDER: And -- but you say that you ascertain what's going on in Kitchener in discussions regularly between Union and Kitchener. 845 MR. ROGERS: Yes. Kitchener, as either an M9 but certainly now as a T3, is one of our largest customers, and the way we are organized, we have specific teams of people that serve our -- whether it be the large industrial, the large power, or, in this case, the large T3 wholesale customer of CCK. And we do have ongoing -- with those 76 and with Kitchener and the other two M9 customers, ongoing discussion. We do not have specific discussion with all 600 of our smaller industrial/commercial customers because it just wouldn't -- it just doesn't make economic sense to go out and spend the time with 90 percent of the small end of your market that represents a small volume. But we do certainly with you and the large industrials. 846 MR. RYDER: Yes. And Kitchener used to rank number 4. Is that where it ranks now in terms of volume? 847 MR. ROGERS: I'd have to go back and look. Certainly it would be in the top 20. The only reason I say that is we have a large number of power customers, so I'd have to go back and look. But CK is one of the largest. 848 MR. RYDER: In these ongoing discussions between Kitchener and Union, Union has not ascertained the heat-sensitive component of Kitchener's load? 849 MR. ROGERS: No. And once again, we don't weather-normalize any of those top -- we don't weather-normalize any contract customers, and we don't weather-normalize the large industrials or the large wholesale. 850 MR. RYDER: And notwithstanding these ongoing inquiries, you're not aware of any discussion which specifically addressed the T3 volume forecast prior to your white-page filing? 851 MR. ROGERS: I believe there was discussions, but then there was a submission, I know, by CCK later. 852 MR. RYDER: Yes, after your white-page filing. 853 MR. ROGERS: Right. I believe there's an interrogatory -- I can't put my finger on it; we could look at it -- which explains our position. 854 MR. RYDER: That's J.5.24. But there's no discussion prior to your white-page filing, and the material that Kitchener provided after your white-page filing didn't prompt you to alter your forecast. 855 MR. ROGERS: I would say there was discussion. There's been ongoing discussion. But when this letter was received from Kitchener on July 14th, 2-03, in the answer to our interrogatory, we discussed why we chose the way to forecast it versus the one that was submitted, because of the facts as we saw them. 856 MR. RYDER: One final undertaking to me -- well, yes, based on the facts as you saw them. What were those facts? 857 MR. ROGERS: Again, we've answered that in part C of J.5.24. 858 MR. RYDER: Okay, I understand. 859 Now, can you provide, this is my last undertaking request, can you provide the impact on the revenue deficiency for the T3 rate class caused by adding an additional 10(3)m3 to your forecast? 860 MR. ROGERS: Sorry, just so I understand, the impact of adding one -- 861 MR. RYDER: 10,000. 862 MR. ROGERS: Sorry. 863 MR. RYDER: Adding 10,000, 10(3)m3. 864 MR. ROGERS: It would be a similar undertaking, I think, to what we said we could do, this morning, for Mr. Thompson for all rate classes. It would simply be a T3 customer class of -- 865 MR. RYDER: Yes. And can you make the assumptions, do one assuming no change in the CD and one assuming a CD change? 866 MR. ROGERS: What would you like to change the CD to? 867 MR. PENNY: Mr. Chairman, the City of Kitchener has a contract with a CD, there's no point in changing that. That's not going to happen. 868 MR. ROGERS: April 2005. So for the test year, that's a good point, a moot point. 869 MR. RYDER: The CD is at risk of changing if there's a volume increase, though. I mean, all the T1 -- all the T1 customers have contracts with CDs stipulated in them. 870 MR. ROGERS: Right. And we don't change them unless there's some material which they explain to us varying up or down in a change-plant operation. If there is or if it's a new customer, you would review the CD. But we don't arbitrarily add or increase the CD if someone is going to use more gas unless there is some material uptick in their volumes. 871 MR. RYDER: Volumes. I'm saying there is an uptick of 10,000. 872 MR. ROGERS: So you're saying let's imagine -- 873 MR. RYDER: Let's assume that activates the automatic escalation clause in a contract with a CD, and that the CD goes up correspondingly. 874 MR. ROGERS: I think we can do it. I don't know why we can't. Yeah, we'll do it. 875 MR. SOMMERVILLE: Thank you, Mr. Rogers. 876 Just so that we're clear on exactly what the undertaking is, Mr. Ryder, do you want to stipulate the undertaking? 877 MR. RYDER: It's precisely the same as Mr. Thompson's request with a 10,000, 10(3)m3 number. 878 MR. ROGERS: Yeah, we'll do it that way. That's fine. 879 MR. RYDER: I take it that when a T-customer desires to increase their CD, there's a way of doing that, there's a protocol for doing that? 880 MR. ROGERS: Yes. Again, what we do is sit down with the T-customer and review if there is -- they have to demonstrate to us there's a material change in production or plant operations or closure or growth or something that is, you know, we can point to that justifies the change in CD. 881 MR. MORAN: Mr. Chair, sorry, I think we have an Undertaking N.4.5, undertaking to redo the Kitchener forecast reflecting a 10,000, 10(3)m3, under two scenarios; one with a contract change, and one without a contract change. 882 UNDERTAKING NO. N.4.5: TO REDO THE KITCHENER FORECAST REFLECTING A 10,000 10(3)m3 UNDER TWO SCENARIOS; ONE WITH A CONTRACT CHANGE AND ONE WITHOUT A CONTRACT CHANGE 883 MR. SOMMERVILLE: Thank you, Mr. Moran. 884 MR. RYDER: And are you aware that this year -- and I take it if a customer is straining within their CD and they go over, there are penalties? 885 MR. ROGERS: Yes. 886 MR. RYDER: And are you aware that Kitchener asked for -- to raise its CD recently? 887 MR. ROGERS: Again, what we look at is a demonstration of something behind it to drive that change. 888 MR. RYDER: Yes, sir. I just asked if you're aware that Kitchener claimed that it required an increase in the CD. 889 MR. ROGERS: What's confusing me is we -- let me just -- just let me understand. We have a contract in place for the period of time and it's set with -- as I recall the contract, there are mechanisms to correct for the change in CD, and if the mechanisms are triggered after a bandwidth of tolerance, that will automatically change and restructure or reset the CD. So there's a very mechanical process laid out in the existing contract which is negotiated between the parties, so I'm not sure what a request to change it would do in the middle of a contract term. 890 MR. RYDER: All right. There has recently been negotiations to renew the contract. 891 MR. ROGERS: The contract renews in 2005. 892 MR. RYDER: Yes. And there have recently been negotiations -- 893 MR. ROGERS: Discussions, yes. 894 MR. RYDER: Respecting a renewal? 895 MR. ROGERS: Yes. I'm not sure what that has to do with 2004, just for the record. 896 MR. RYDER: It relates in this way: During those discussions, wasn't there a request by Kitchener to increase its CD? 897 MR. ROGERS: I need a point of clarification. We have a contract in place until April of 2005 which is set, and we have started negotiations earlier than the contract stipulation is in the contract for the renewal, and so I'm not sure what the discussion for 2004 -- what bearing this has on it. I don't want to be my lawyer. Maybe I'm speaking out of tune here. But I just don't know how to tie this in with what we're talking about here, Mr. Ryder. That's my difficulty. 898 MR. RYDER: With respect to this last point and the next point after that, they won't be long, Mr. Chair, but with the Board's leave, it would be more efficient, I think, if you allow Mr. Quinn to take over. 899 MR. SOMMERVILLE: It's an unusual request insofar as it is -- I've only ever seen it done once before, actually. 900 MR. RYDER: Yes. 901 MR. SOMMERVILLE: And I think it involved the same parties. I'm prepared to permit this indulgence, so long as it's very limited. Generally, I think it's a bad idea. 902 MR. QUINN: Thank you, sir. We did describe what we were talking about to Mr. Penny. However, in clarification and getting to the point here, I'll close this off, go to a couple of follow-up issues from this morning, and try to do it in a very constrained time frame. 903 CROSS-EXAMINATION BY MR. QUINN: 904 MR. QUINN: Mr. Rogers, just relative to the last -- I was trying to give Alick the words that would be helpful, but you described the bandwidth that's in the contract. How does Kitchener access that bandwidth? 905 MR. ROGERS: I'm going by memory because I haven't looked at it in great detail. As I recall, there's a bandwidth of around 100, 10(3)m3 under which there's a tolerance for if the volumes move up on any day to there, and it will not trigger the mechanism to reset the CD which is automatic. 906 Above and beyond that bandwidth, as I recall, it has to then happen twice, and if it does, then the CD is reset at the average of the two occurrences and moves the CD level up. 907 MR. QUINN: That's a very good summary with one missing component and that's Kitchener's responsibility in that to access the bandwidth. What does Kitchener need to do so access that? I could provide it to you and you could take it subject to check if that's easier. 908 MR. PENNY: Well, the contract, Mr. Chairman, is in the record. It's Exhibit J.5.2. I imagine the contract speaks to this issue, and frankly, it's not clear to me why it's necessary to examine the witness about it if the provisions are in the contract. And that's even assuming the issue of Kitchener's contract that doesn't expire 'til 2005 is even relevant in this case. 909 MR. QUINN: It goes to costs, sir, and the forecasts we submitted. 910 If you would be willing, Mr. Rogers, I could summarize it in 10 seconds and you could tell me if that's your understanding, or you can take it subject to check. 911 MR. SOMMERVILLE: Proceed, Mr. Quinn. 912 MR. QUINN: Kitchener provides additional gas at Parkway on that given day, and if we provide additional gas at Parkway it reduces Union's requirements on their system; therefore, Kitchener does not have to take an increase in CD. Is that your understanding? 913 MR. ROGERS: Mr. Poredos, can you help me with this one? I'm just a tad out of my -- 914 MR. POREDOS: I certainly don't know the contract, because I haven't been involved it, nor do I know the provisions under the contract for disposition of changing in the CD. What you're doing is delivering gas at Parkway and basically doing a back-haul on Union's system to Kitchener. The city gate volume, though, stays the same. I don't understand what would change, regardless of whether it comes from Union's storage or on the Don to Parkway system from the west or the east, your city gate volume would be the same. That's about all I can add because I don't understand the insides of the contract because I haven't been involved with it. 915 MR. QUINN: Fair enough. I will accept that and we will rely, as Mr. Penny is suggesting, on the contract. But given the context, and I guess we'll need to take it up with gas supply and cost allocation later on, that's why it's apparent in our position, the City of Kitchener, that this is relevant to the issue at hand and this proceeding. We'll take it from there, thank you. 916 I just wanted to go back to a couple of points this morning. Since I'm talking with Mr. Rogers, I'll start with your cross-examination with Mr. Thompson this morning. You referred to an interrogatory J.1.56, and that's switchable volumes, basically the amount that can go from one fuel to another, and Union's ability to retain those volumes? 917 MR. ROGERS: I'm just looking it up. I have it now. 918 MR. QUINN: Thank you. I wanted to go back. As you were going through what has happened with the gas price, I don't follow maybe as closely as you or some of the other people at Union, but quite frankly, as I look at these numbers, I figure -- I believe that the gas price is one component and the other price that is impacting this table is the oil price? 919 MR. ROGERS: Yes. 920 MR. QUINN: Can you comment on the oil provides of 2001 versus the oil price of a contract going forward for 2004? 921 MR. ROGERS: I can't tell you the exact number. What I do know is that Union was -- as it reflects in line 3 of J.1.56, that the oil price was lower in 2001 than the gas price, resulting in our erosion of our alternate fuel market share. 922 MR. QUINN: So when you did this analysis and the data on the interrogatories at the bottom, would you consider what the oil price is at that point to go forward to make your forecast for 2004? 923 MR. ROGERS: It would be the relative -- you'd look at the relativity of the pricing and forward curves. I don't want to ask Mr. Poredos too many questions, but I know he has written evidence supporting the gas price going forward. 924 MR. POREDOS: Going forward? 925 MR. ROGERS: Yes. 2003 -- 926 MR. POREDOS: The expectations are that the gas price will be at the level it is today, assuming normal weather, going forward. Now, obviously, if we have colder weather during this winter, we'll have a repeat of last winter where there will be a high drive-up of prices. If we have a warmer winter, it will drop below that. But in essence, or in general, the gas price is probably going to be at the level it is today for some time. 927 MR. QUINN: Okay. 928 MR. ROGERS: Just to add to that, there have been some changes in the situation around alternate fuel and pricing since 2-01. 2-01 referred to the changes that really have occurred as a fallout of Enron, the failure of Enron, if you will, the meltdown of the trading opportunities, and in fact, it's reduced the number of traders and marketers. We see our liquidity dropping. We see the smaller providers of gas services and commodity not being able to participate because of credit requirements that are being put onto their companies by virtually everyone now since the failure of Enron and its fallout. So what we're finding as well is that those three things, in combination with the high commodity price relative to the high-delivered commodity price of oil, is driving the price up even higher than it was in 2001. So our numbers that we have going forward, we feel, are correct, and that the price will be sustainable not only because of that but because of restrained supplies of natural gas, which I think everybody is aware of. So there is a changed circumstance. 929 MR. QUINN: So if I summarize what Mr. Poredos and Mr. Rogers said, basically the prices are going to remain at this relatively high level for calendar year 2004, which is the base year you're looking at? 930 MR. ROGERS: That's correct. 931 MR. QUINN: And the oil prices, though, and that's the focus of my question, the oil prices of 2004 relative to the oil prices in 2001, did you assess the difference? 932 MR. ROGERS: We didn't assess the difference of '01. What we assessed was there's a similar or larger differential competitive advantage for oil versus gas, and that's what we look at as opposed to the absolute number. It's the relativity as opposed to -- 933 MR. QUINN: Relativity of 2001 versus 2004. 934 MR. ROGERS: No, relativity to 2003 and -4 delivery gas prices versus the predicted 2003 and -4 oil price. 935 MR. QUINN: Okay. Thank you. 936 Mr. Poredos, just to finish off, you had talked about the long-term storage premium and you had provided some numbers that may be in your evidence but I wasn't able to find them before. So it's helpful to hear that you've renewed approximately 50 pJs, I think is what you said this morning, and there are 24 pJs that are up for renewal? 937 MR. POREDOS: Of storage? 938 MR. QUINN: Yes. 939 MR. POREDOS: That's the M12 storage going to C1. That does not include short-term storage that's sold on a year-to-year basis. 940 MR. QUINN: Thank you for the clarification. In terms of those M12 being renewed into a long-term contract, the long-term storage premium that you've placed into evidence, does it reflect the average price of renewal -- maybe I'll ask you the question: What was the average price of renewal for 50 pJs? If that's in the evidence, where request I look it up? 941 MR. POREDOS: I don't believe I have that specific number. Our assumption as I had in evidence, and I believe it was in my white-page evidence, stated that our assumption for forward long-term storage, that we were going to be running around a 65-cent Canadian number. Now, that number will go up and down. Markets change. Even this year, when we were here earlier, we were talking about storage, in fact, being at a negative value where customers -- we would have to may pay a customer to take the storage because it's of no value. The price today is higher than it will be tomorrow. 942 I did actually provide an interrogatory, which is J.34.42. If you could take a look at that, Mr. Quinn, you can see the high and low pricing that we had reviewed historically, in fact, as to where the pricing would have been at any one time. You cannot price storage on a forward look to say tomorrow it's going to be worth what it is today. It's the day of the NYMEX markets, what's the value. What's the differential on that value between today and tomorrow is what the value of storage really drives. 943 MR. QUINN: These long-term contracts are what length of time? 944 MR. POREDOS: They are a varying length of time. 945 MR. QUINN: Maximum length of time is? 946 MR. POREDOS: I believe 2009 is the longest one that we've signed. 947 MR. QUINN: Okay. Does the market move much on a day-to-day basis between now and 2009? 948 MR. POREDOS: The market may move between now and 2009. The customer -- the customer has decided what the market value for that storage is over that period of time. So the value that the customer is willing to pay is a part of the negotiation that Union must go through to say that, We believe its value is, perhaps, 70 cents, and then the customer says, No, I'm willing to pay 60 cents, and we have to negotiate to some price based on some factual data. 949 MR. QUINN: Okay. Then I still am requesting the average price for the 50 pJs and then if you take that and you extend it to the additional 24, what would your long-term storage premium look like for 2004. 950 MR. POREDOS: You want this as another undertaking? 951 MR. QUINN: Sure, if that's easier. 952 MR. POREDOS: I'm not sure how I would do that in terms of knowing that the -- are you asking me for an extension of the contracts, just the one year or fully to the... 953 MR. QUINN: You were providing a value for 2004 in your evidence. 954 MR. POREDOS: That's correct. 955 MR. QUINN: In that evidence you're saying the 24 pJs would be up for renewal. 956 MR. POREDOS: That's correct. 957 MR. QUINN: Take the average of what you got for the 50 pJs and provide it with the additional 24, that renewal value, and provide us with what the long-term storage premium would be. 958 MR. POREDOS: And is the assumption that the customer is signing for a provision with deliverability inventory provided by the customer or by Union? 959 MR. QUINN: In your 50 pJs, what was the predominant choice in that regard? 960 MR. POREDOS: There may be some of each, but the customers are providing their own deliver -- 961 MR. QUINN: Then retain that consistency, then choose the customer providing the inventory. 962 MR. POREDOS: Okay. Could you just repeat exactly what you would like in that undertaking, please, so that we are not -- 963 MR. QUINN: I want to make sure there's clarity and I'll be finished, sir. 964 For Union Gas and the 50 pJs that have been renewed, to provide the average value of renewal, then extend that to the 24 additional pJs to be renewed and provide what the calculation would come up with as the long-term storage premium for 2004. 965 MR. SOMMERVILLE: It's simple arithmetic extrapolation from those that have been renewed to those that are still outstanding. 966 MR. QUINN: Just so that I understand, and the record would be clear, that would be your total long-term storage premium, Mr. Poredos, or is there any additional that would come into play? 967 MR. POREDOS: In the long-term premium account? 968 MR. QUINN: Yes. 969 MR. POREDOS: And the question again is, sorry? 970 MR. QUINN: If you take the 74 pJs, which is the sum of the 50 and the 24, if you added those two values up, would that be the total number of storage in your long-term storage premium, or are there any other aspects of storage that would generally be reported as long-term storage premium? 971 MR. POREDOS: That would include all storage that is sold long term, greater than one year. 972 MR. QUINN: Thank you very much. 973 MR. MORAN: That would be Undertaking N.4.6, Mr. Chair. 974 UNDERTAKING NO. N.4.6: FOR UNION GAS TO PROVIDE THE AVERAGE VALUE OF RENEWAL OF THE 50 PJS, THEN EXTEND THAT TO THE 24 ADDITIONAL PJS TO BE RENEWED AND PROVIDE CALCULATION RESULT FOR THE LONG-TERM STORAGE PREMIUM FOR 2004 975 MR. SOMMERVILLE: Thank you, Mr. Moran. 976 Are those your questions, Mr. Ryder? 977 MR. RYDER: Yes, thank you. 978 MR. SOMMERVILLE: Mr. Rattray? 979 MR. RATTRAY: Thank you, Mr. Chairman. 980 CROSS-EXAMINATION BY MR. RATTRAY: 981 MR. RATTRAY: At the outset, if we could mark as exhibits, there are a number of documents I'd previously provided to Mr. Penny and the Union representatives, and distributed amongst counsel, if we could provide those documents with exhibit numbers. 982 MR. MORAN: Mr. Chair, you've got a set of four documents. 983 MR. RATTRAY: The first document is Pickering A and Bruce A units return to service assumptions based on IMO 18-month outlooks. 984 MR. MORAN: That would become Exhibit M.4.1. 985 MR. RATTRAY: Would that not be 4.2? I understood you to have marked one of Mr. Ryder's exhibits as 4.1. 986 MR. SOMMERVILLE: Yes. The interrogatory from EBRO 499. 987 MR. MORAN: That's right, Mr. Chair. I didn't mark it on my list. So this will be M.4.2 that would be a document entitled "Pickering A and Bruce A units return to service assumptions based on IMO 18-month outlooks." 988 EXHIBIT NO. M.4.2: DOCUMENT ENTITLED "PICKERING A AND BRUCE A UNITS RETURN TO SERVICE ASSUMPTIONS BASED ON IMO 18-MONTH OUTLOOKS" 989 MR. SOMMERVILLE: Thank you. 990 MR. RATTRAY: The next document would be volume actual versus forecast. 991 MR. MORAN: M.4.3, document entitled, "Volume Actual Versus Forecast" 992 EXHIBIT NO. M.4.3: VOLUME ACTUAL VERSUS FORECAST 993 MR. RATTRAY: The third document would be "Revenue Actual Versus Forecast." 994 MR. MORAN: M.4.4, document entitled, "Revenue Actual Versus Forecast." 995 EXHIBIT NO. M.4.4: REVENUE ACTUAL VERSUS FORECAST 996 MR. RATTRAY: And the last document is entitled "Additional Revenue for Each 100,000 10(3)m3 Increase in Contract Volume." 997 MR. MORAN: And that would become Exhibit M.4.5, Mr. Chair. 998 EXHIBIT NO. M.4.5: ADDITIONAL REVENUE FOR EACH 100,000 10(3)m3 INCREASE IN CONTRACT VOLUME 999 MR. RATTRAY: Thank you. 1000 Are you ready, Mr. Rogers? 1001 MR. ROGERS: I am. 1002 MR. RATTRAY: Thank you. At the outset I'd like to start with a review of the purpose behind this forecasting exercise in order that it's clear to me and hopefully for the Board. And if I understood correctly an answer given earlier today by Mr. Gardiner, the purpose of looking for a forecasting methodology is to come up with something that is stable, simple, sustainable; you want it to recognize what's happening in the world and you want a fair chance of getting it right. 1003 Is that a fair summary of your evidence earlier today, Mr. Gardiner? 1004 MR. GARDINER: In reference to the weather-normal, yes. 1005 MR. RATTRAY: All right. Is it restricted to weather-normal or is it for a reasonable objective for forecasting in general? 1006 MR. ROGERS: I would like to answer that. In terms of the customer -- the contract customer group that I'm responsible for is very heterogenous by nature. I think that the description that Mr. Gardiner gave does cover predictable homogenous markets that would move slowly from year to year but is not necessarily appropriate for heterogenous highly swingable loads such as those in my market. 1007 MR. RATTRAY: But in terms of an objective, I take it you don't dispute the fact that you do want to come up with a forecast methodology for your own group that recognizes what's happening in the world and gives you a fair chance of getting the number right? 1008 MR. ROGERS: The world is probably less influential. Only on my very largest customers, the regional issues, such as the oil and gas price and the other competitive issues, are much more germane. And also, there is much more fuel-switching capability in my market than the market that Paul has described. It's a firm market that doesn't change. I have a highly volatile market, and we've already established that fact. 1009 MR. RATTRAY: Yes. But in terms of an objective, I'll step back one level, you're seeking to try and predict future events with a high degree of accuracy, in a consistent manner. And I recognize that you've testified as to the inherent volatility of certain elements that you must deal with, but your objective, nonetheless, is trying to predict them with a high degree of accuracy. 1010 MR. ROGERS: It would be, and tempered by three issues, the issues related to the power market, the issues related to volatile gas pricing, and the high fuel switchability of my market. Subject to those three factors, yes. 1011 MR. RATTRAY: Do you have any sense, sir, of what you would consider an acceptable degree of variance between forecast numbers and actual results? 1012 MR. ROGERS: We've never tried to establish that. We've always tried to reflect what the true conditions were, and that's the way that we forecast our markets. We don't have target numbers of variance. 1013 MR. RATTRAY: Well, do you have any performance standards that you're trying to achieve in terms of stating what the variance would be within a certain percent? 1014 MR. ROGERS: No, we don't. And you wouldn't necessarily want to incent anyone, if you're going high, to promote conversions to alternate fuel to make your targets, for instance. I mean, that's where this would cut both ways and you have to be balanced in your point of view of the variability, which is very volatile in my market. Again, it would work closer -- I can't answer for my colleague, whether the targets are different for the more predictable and homogenous smaller market. 1015 MR. GARDINER: Well, I can say, looking at the general service market, that the industrial class is a more challenging class to forecast than the residential class. As Mr. Rogers indicated, it may be a very large class in terms of numbers, but the average consumption per customer is low. And statistically, I can analyze that market because of the stable patterns in consumption. 1016 The point with the industrial general service class is that for some of the reasons that Mr. Rogers talked about, that even in these small, light manufacturing show-up, the range of predictive capability of my equations is wider than for my residential. 1017 Now, Mr. Rogers, he has a very, very challenging task because his customers are huge, and he mentioned earlier this morning the whole issue of when the nukes come on can move his market. That's not something that shows up in my market. 1018 MR. RATTRAY: Thank you. I would ask that you bring out before yourself, Mr. Rogers, Exhibit C.1, tab 2, which is your prefiled evidence, along with the update. My questions will, for the most part, be directed to you since my interests lie with contract customers. 1019 MR. ROGERS: Is it the white-page evidence or the -- 1020 MR. RATTRAY: The white page and your update. 1021 MR. ROGERS: Okay. 1022 MR. RATTRAY: Before we get going, when were the forecasts prepared and updated with respect to the years 1999 through to 2000? 1023 MR. ROGERS: You're asking me for all of the dates for the five years? 1024 MR. RATTRAY: Well, approximately, when were they done? Was 1999's forecast, as set out in various -- 1025 MR. ROGERS: Typically, nine to 12 months in advance of the contract year in order to allow Mr. Poredos and others to plan the assets that they need to run the business when we hit that year 12 months later. So 12 months in advance. The blue-page update is a five and seven of the current year. 1026 MR. RATTRAY: So I take it, then, from reviewing your resume and CV, that given that you've been the director of sales and marketing since 1999, you would have been involved, then, with the preparation of the forecasts with respect to the contract customers for the years 2000, 2001, 2002? 1027 MR. ROGERS: Yes, that's correct. 1028 MR. RATTRAY: The 2004 forecast that you put forward, that was prepared when? 1029 MR. ROGERS: The 2004 forecast would have been prepared in the late summer of 2002 for the white page, updated in May of 2003 for the blue page. 1030 MR. RATTRAY: Thank you. 1031 MR. ROGERS: May/June of 2003. 1032 MR. RATTRAY: When you did your update, I take it you incorporated all relative and pertinent information? 1033 MR. ROGERS: We certainly did. 1034 MR. RATTRAY: All right. Turning to Exhibit C.1, tab 2, there is a description of the forecast methodology. 1035 MR. ROGERS: Do you have a page number for me, please? 1036 MR. RATTRAY: I would describe a large part of your evidence, sir, as describing the background to how you approach it, and then in your section you have "Union's industrial forecast methodology," that is the bottom of page 2 is the heading. You get into the body of it then on page 3. 1037 MR. ROGERS: Okay. Yes, I have it. 1038 MR. RATTRAY: All right. This methodology, would you describe it as a common, well-established practice? 1039 MR. ROGERS: It's a common, well-established practice that that's how we forecast the large customers, the 76 that I speak about here. By their nature, refineries, steel, chemical, very large customers, power generation, which are the most difficult to forecast for the reasons that I've told the Board this morning. This methodology is the one that we believe works the best. 1040 MR. RATTRAY: Have there been any substantive changes in this methodology since you became responsible for the forecasts for this area in 1999? 1041 MR. ROGERS: No, it hasn't. And the three big drivers are gas pricing and the availability of the nuclear units and the opening of the electricity market, were the three biggest contiguous issues that we faced from 1999 through to now. 1042 MR. RATTRAY: To assist you in your forecast, you assess and compile forecasts for each large contract customer? 1043 MR. ROGERS: We have an ongoing discussion with the 76 large customers, as we describe it here, and based on those discussions with them and their points of view of their operation, whether it be growing or retracting due to the market conditions and relative energy prices, as well as their component alternate fuel switchability, all of those factors we weigh in and then have the forecast for each of those large customers. 1044 MR. RATTRAY: You would then take this information, sir, and use it in conjunction with historic load? 1045 MR. ROGERS: Yes, in most cases, except for the one -- our biggest dilemma in forecasting throughout this has been the one oil-filed merchant plant that we converted to gas that was to be on a -- in fact, I think, as I recall, it's your customer. And it's been in the most difficult because it was forecasted and contracted for and a minimum annual volume put in the contract, expecting it would be a peaking load. And that if the nuclear units returned and the electricity market opened, and if we could -- that it would run. Then if it run, what we had to know was the relative pricing between oil and gas. 1046 What we established prior to this was that we do the forecast 12 months in advance. We really don't know what the situation is between the oil and gas price. So even if the units would have ran, or been available to run more, they would have had to then beat oil, which is almost impossible to forecast 12 months in advance, which is why we set that particular customer at its contract minimums for the term. 1047 MR. RATTRAY: So having gone through your answer, there are quite a few "ifs" there, if this, "if that," et cetera, so is it fair to say that after you've done your assessment and compilation of forecast for each customer, including the merchant power sector, you exercise a fair degree of discretion in determining what you think is a reasonable forecast. 1048 MR. ROGERS: What I've just described is the methodology we described in 499, our last case. And if you look back, it was then that we established the issue and the relationships between alternate fuel. 1049 At that point in time, the volatility and the difference between the oil and gas price was the major driver of the differentiation. What happened then, since 1999, with a proliferation of the highly dispatchable and discretionary power generation loads, very large; and when they arrived on the scene new, in 1999, particularly the interruptible loads, which is the large merchant cogen, the oil and gas-fired boiler load, it just created a new challenge for us to forecast it. 1050 So we used the factors of the competitive alternate price between oil and gas and what we were made aware of, the same as the rest of the public and the world, in terms of what the availability of the nuclear and the opening of the market would be. And so that assessment we applied, and each year, the market opening was delayed and the -- and the return of the nukes was delayed. 1051 That's really why there have been no new additional plants, gas-fired plants, brought on since the Sarnia regional cogen was brought on in 2003. The Brighton Beach plant will be brought on in 2004, and Imperial Oil in 2004. Other plants are now stopped in the development because of the uncertainty of the market. 1052 So I would offer that that is a dramatic changed circumstance from what we experienced prior to 1999, and so that volatility of the electric power generation, gas-fired electric power generation, the discretionary portion of that, has been our biggest challenge no doubt about that. 1053 MR. RATTRAY: Sir, if I can come back to my question, sir, it was: Would you agree with me that it requires you to exercise a fair degree of discretion in determining your forecast for that sector? 1054 MR. ROGERS: I don't believe it's discretion, I believe it is understanding the facts that are widely accepted at the time and applying those to the forecast to generate the numbers. 1055 MR. RATTRAY: You must make an assessment. 1056 MR. ROGERS: That's right. Taking all the information into account, we must make an assessment. 1057 MR. RATTRAY: In one of your previous answers in describing this large facility that could switch between gas and oil, you indicated that because of that, you had to set it at the minimum? 1058 MR. ROGERS: The contract was laid out for 15 years in its original intent, and the targets were to -- it was to be a summer-peaking load which would run primarily until the nuclear units were returned. That's the way that it was laid out. 1059 The contract, as it now turns out, has the contract minimums which should have taken 15 years to satisfy, in fact, were satisfied as of August 31st, 2003. So since that day, we no longer have any minimum contractual commitment from the customer to burn. So that is another material-change circumstance for the balance of 2003, and certainly for 2004. We find ourselves with no contractual minimum take, we find ourselves with oil and gas prices definitely at the advantage of oil over gas, and we find ourselves with roughly 3,300 megawatts of nuclear power and new merchant plants returning of which we have 1,068, 10(6)m3 in the forecast. 1060 So we have simply replaced those low efficiency volumes that we do not expect to burn with the higher efficiency gas-fired volumes that we know will be dispatched because they're higher efficiency. Drop the nukes in on top of that, and we think we'll push the availability of the less efficient merchant cogen to the back of the dispatch stack again. 1061 So I think it's prudent, and that's the way we did it. 1062 MR. RATTRAY: What I'd like to explore with you is why you felt it necessary to just set your forecast at the minimum. I would have thought that, given your role in endeavouring to forecast, you would go beyond the minimum and consider what is likely. 1063 MR. ROGERS: We would have. If anyone could tell me 12 months in advance, when you set the forecast, of what the oil and gas price ratio would have been, that would have been the first thing. If anyone could have told me that the market was or wasn't opening, the Ontario electricity market, that would have been a good thing. If anyone could have tell me whether the nuclear units were going to return 12 months in advance, I would have taken that into account. 1064 For four years, the nukes were supposed to be back, the market was supposed to be open, and we didn't know what the oil and gas relationship would be; therefore, we thought setting it at a minimum, which was very healthy, was a fair and equitable way and a balanced way to set the forecast for that merchant cogen. 1065 MR. RATTRAY: So it was better to err on the side of being conservative than your forecast. 1066 MR. ROGERS: I would disagree. I think we were very prudent in the way we did it. 1067 MR. RATTRAY: Is there a reasonablity test for your forecast for contract customer demand? 1068 MR. ROGERS: I have no idea what a reasonablity test is. That's the first I've heard of it today with Mr. Gardiner. I didn't even realize that the regulated market applied it so I have no idea what it is. But we do not have anything -- we do not apply that to our markets, again, because it is a heterogenous, highly volatile set of customers versus a homogenous, highly predictable firm non-fuel switchable, proof that the reasonablity test is applied to. 1069 MR. RATTRAY: At page 4 of your prefiled evidence, sir, you state that there is ongoing volatility and legislative change in the Ontario electric power generation market and that this represents both risk and opportunity to the customer demand forecast. 1070 MR. ROGERS: The risk is the lowering of the merchant plants. 1071 If I could turn you to -- I think this might help if we go to page 10 of 12 of that Exhibit C.1, tab 2. The reference I'm making under the power -- under that discussion is that -- if we go then to lines 19 and 20, what I'm talking about is Union has added in growth of new high-efficiency gas-fired electric power generation which increases the forecast by 1,068, 10(6)m3, which is offset by a decline of 952, 10(6)m3 at the older existing peaking facilities and the independent power producers. 1072 And I described this morning the dilemma with the independent power producers, being that we believe that they will run at the minimum firm commitments based on two things; they too are impacted by the fact we have added the new cogeneration, the nuclear units returning. And what we experienced in 2001 with these independent power producers was that they have long-term contracts for natural gas. As soon as the natural gas price runs up, they like to -- they are focused on making profit, not on making electricity. So what they will do, typically, in a winter when it's the highest prices, they will sell off the natural gas for a profit, hence only fulfilling the minimum contractual burn. That's what happened in 2001. That's what we believe is going to happen in 2004, because the gas prices are predicted to stay up. 1073 Those two factors, we've replaced 952 of older inefficient capacity and IPP with 1,068, 10(6)m3 of high efficiency. 1074 MR. RATTRAY: Thank you. At page 4 of Exhibit C.1, tab 2, you also indicate that a significant proportion of the forecast is attributable to customers who generate electric power. Can you tell me what percent of the contract customer demand is related to electric power, and can you also provide a breakdown with respect to M7 firm and R25? 1075 MR. ROGERS: I'm just looking for a reference, so I did hear. Let me see if I can find the proper reference. 1076 MR. SOMMERVILLE: Mr. Rattray, if you can find a convenient point, we'd like to break for a short break, just 10 minutes. I'll leave that in your hands. 1077 MR. RATTRAY: Certainly, Mr. Chairman. Now might be an appropriate time. It would allow the witness an opportunity to consult his records. 1078 MR. SOMMERVILLE: Thank you. We'll break for 10 minutes. 1079 --- Recess taken at 3:15 p.m. 1080 --- On resuming at 3:30 p.m. 1081 MR. SOMMERVILLE: Thank you. Please be seated. 1082 Mr. Rattray. 1083 MR. RATTRAY: Thank you. 1084 Before the break, Mr. Rogers, you were going to consider whether you could answer today, or whether you'd like to provide it as an answer to an undertaking, my request for a breakdown of the percentage of customers using gas to generate electricity. 1085 MR. ROGERS: I think we should be able to do that today. That's what I did over the break. 1086 If we can look at Exhibit J.26.30. 1087 MR. SOMMERVILLE: Sorry, what was that reference? 1088 MR. ROGERS: Sorry, Exhibit J.26.30. 1089 MR. RATTRAY: Yes. 1090 MR. ROGERS: So if we look at that, that gives the two numbers. The question was asked: What is the number in our blue-page update for the power generation market component or segment. The number for the update is 2,582, 10(6)m3. If I refer you then by cross-reference to -- let me make sure I get the right number -- J.17.15. 1091 MR. RATTRAY: Yes. 1092 MR. ROGERS: Sorry, that's 2002. I need to go to my -- I need to go to my blue-page evidence, and that is under Exhibit C.1, tab 2, page 4 of 5. The number for the blue-page total market under my responsibility is 9,351, at the bottom of my evidence, under line 10, under column C. 1093 MR. RATTRAY: Yes. 1094 MR. ROGERS: Which, if we did the division from Exhibit J.26.30, sorry I ran out of time, but 2,582 divided by 9,351 would give you a percentage, and my colleague is calculating that as we speak. 1095 MR. RATTRAY: Yes, I think you may have misinterpreted the question, sir. My question was directed to asking what percentage of the contract customer demand is attributable to customers using gas to generate electricity, and then I asked further, I'd like a percentage breakdown -- 1096 MR. ROGERS: Let me just understand this. 1097 MR. RATTRAY: Allow me to finish the question and we'll move further. And then I'd like a breakdown with respect to M7 firm and R25. I want to know what percentage of the demand is attributable to electricity generation. 1098 MR. ROGERS: I'm sorry, the -- 1099 MR. PENNY: I think that's what you just got, Mr. Rattray, was 2,582 divided by 9,351 gives you the percentage of gas-fired electricity. 1100 MR. ROGERS: Which is 27.61 percent for the blue-page update 2004. 1101 MR. RATTRAY: Are you attributing then all of these other classes that are set out at page 4 of your update, the rate M4, M7, rate 20, rate 100, rate T1, M5, and 25, they are all attributable to electricity generation? 1102 MR. ROGERS: I understood your question to be what percentage of Union's total through-put for the contract market for 2004 in the blue-page update is for electric power generation, and the answer is 27.61 percent. 1103 MR. RATTRAY: Okay. Can you give me a breakdown, then, with respect to the M7 and R25 categories? 1104 MR. ROGERS: I don't have that broken down. These categories, it's embedded in here. I can give you an approximate but I'd have to go back and do an exact -- 1105 MR. RATTRAY: I'd be happy to take your undertaking to give me your estimate. 1106 MR. ROGERS: I think we can do it exactly. I just a matter of I don't have the breakdown. 1107 MR. RATTRAY: That would be fine, sir. 1108 MR. PENNY: M7 and rate 25. 1109 MR. ROGERS: There's also rate 100 included in there, I know, because of the Independent Power Producers. 1110 MR. MORAN: That will become Undertaking N.4.7, the breakdown amongst the rate classes attributable to electricity generation. 1111 MR. SOMMERVILLE: And the relevant rate classes are? 1112 MR. PENNY: M7 and rate 25. 1113 MR. ROGERS: And rate 100. 1114 MR. MORAN: And rate 100. 1115 MR. RATTRAY: Yes. 1116 MR. SOMMERVILLE: So the three rate classes, not two. 1117 MR. ROGERS: And that's what adds up to the 2,582 number. We should tie it to something. I think that's appropriate, Mr. Chairman. 1118 MR. SOMMERVILLE: Thank you. 1119 UNDERTAKING NO. N.4.7: TO PROVIDE THE BREAKDOWN AMONGST THE RATE CLASSES M7, RATE 25, AND RATE 100 ATTRIBUTABLE TO ELECTRICITY GENERATION 1120 MR. RATTRAY: Mr. Rogers, I take it you're familiar with the concept of base-load generation? 1121 MR. ROGERS: Yes. If you could define it for me, I could say yes or no. 1122 MR. RATTRAY: Yes. Well, it's the concept that electricity-generating plants with lower marginal operating costs, such as nuclear plants or hydroelectric plants, would run in preference to higher-cost plants, such as gas plants? 1123 MR. ROGERS: Yes, I agree. 1124 MR. RATTRAY: And would you agree with me that coal is somewhere in between the base-load plants and gas plants? 1125 MR. ROGERS: If I look at what my understanding of the -- that the IMO would use to dispatch the loads, it would be water, which is hydraulic, it would be nuclear, and it would then be some combination of the fossil -- remaining fossil plants; and fossil, including gas-fired and oil-fired and coal, all three. 1126 MR. RATTRAY: Yes. But I would like to position coal in that range. I'm putting to you the proposition that coal plants have a lower marginal operating cost than gas or oil. 1127 MR. ROGERS: I'm not privy to that, what the -- because of the new world, when you dispatch, the dispatch is done not only on the lowest price but on other factors. So what you've said is directionally correct prior to the market opening. I really don't know now that the market is open, and the bid into the markets -- 1128 MR. RATTRAY: Well, to ignore the issue of the other factors but focusing solely on cost, coal is less expensive than gas and oil. 1129 MR. ROGERS: Right. But your independent power, there's 11 of them in our territory, they, I believe, would be dispatched potentially sooner because there is some cost and they're gas-fired. So there are a number of factors that go into what you would call the base-load generation, and I'm not an expert on how to choose which fuels go first. But I would certainly say if they're coal right now, I can tell you from the point of view of fighting coal against coal in industrial markets, that, you know, coal generally is cheaper. But that's not the only determinant here. 1130 MR. RATTRAY: All right. In preparing your forecast of gas consumption you specifically considered and relied upon the IMO's public 18-month forecast? 1131 MR. ROGERS: Yes, that's correct. 1132 MR. RATTRAY: When you prepared the forecast, you relied on the 18-month forecast from April 2002? 1133 MR. ROGERS: Yes, that's correct. 1134 MR. RATTRAY: In particular, you replied on the IMO's assessment of the return to service of various nuclear units? 1135 MR. ROGERS: Yes, we relied on the whole thing, but there were particular nuclear units returning in that mix, that's correct. 1136 MR. RATTRAY: And you concluded, based on your review of the information, that the return of the nuclear units would directly offset and reduce the need for gas-fired generation from the peaking plant? 1137 MR. ROGERS: Yes, that and the fact that the market was due to be open and was open in May of 2002, so those two factors, one being the return of the nuclear, the other being the opening of the market, we took that into account. 1138 MR. RATTRAY: Yes. What in-service date did you use for your forecast for the return to service of the Pickering A units and the Bruce A units? 1139 MR. ROGERS: Without going through the report, I'd have to -- I'd have to review that. But they were due to be back prior to the test year 2004. So whatever the date was, as long as it was less than January 1, 2004, it supported our data. Subject to looking back, the number was prior to 2004. 1140 MR. RATTRAY: So your source of information was the IMO's 18-month report. 1141 MR. ROGERS: That's correct. That's what we used. It's a well-accepted document and -- 1142 MR. RATTRAY: Yes, and you were relying on the April 2002 18-month forecast and assessment by the IMO. 1143 MR. ROGERS: Yes, and it's quarterly updated, it isn't just a spot report. And we look at the quarterly updated, and I see in your submission, that you quoted from them as well. 1144 MR. RATTRAY: Yes, but for your forecasts that was prepared and prefiled, you relied on April 2002. 1145 MR. ROGERS: Yes, that's correct. 1146 MR. RATTRAY: In your update, your blue pages, there's no reference to subsequent IMO quarterly updates; that's correct? 1147 MR. ROGERS: There may not be a reference, but we did look at them so... 1148 MR. RATTRAY: All right. In April 2002, it was forecast, sir, that both Pickering A units would be returning to service; do you remember that? 1149 MR. ROGERS: Yes, that's correct. 1150 MR. RATTRAY: And that Bruce A would have two units returning to service? 1151 MR. ROGERS: I agree. 1152 MR. RATTRAY: You incorporated that into your forecast? 1153 MR. ROGERS: Yes. And when we say "incorporated into the forecast," as well as a number of other factors. But this particular factor, yes. 1154 MR. RATTRAY: Well, I would like your undertaking to specifically advise me as to what date you assumed the Pickering A units and Bruce A units would be returning to service. 1155 MR. PENNY: Well, Mr. Chairman, perhaps I could ask for some clarification of that, because the document M.4.2, that Mr. Rattray has passed out, every one of these uses a date prior to January 1, 2004, so I can't imagine what difference it could make. But perhaps Mr. Rattray could assist. 1156 MR. RATTRAY: Well, it is pertinent, Mr. Chairman, and we'll be getting into it shortly. But I would like the witness to confirm, since he's testified he used it explicitly in the preparation of his forecast, I'd like to explore what dates he had in mind with respect to the return to service of these units. That's an area I intend on exploring with him. 1157 MR. PENNY: My point was he also testified that he didn't care as long as it was before January 1, 2004. 1158 MR. SOMMERVILLE: That was my impression, Mr. Rattray, that, in fact, the witness had indicated that his initial position was derived directly from the April 2002 IMO 18-month outlook, and that you did quarterly -- and I think this is the burden of the evidence, that you regarded the quarterly updates accordingly. 1159 MR. ROGERS: That's correct. 1160 MR. SOMMERVILLE: Does that answer your question? 1161 MR. RATTRAY: It does not, but I can explore it with the witness. 1162 MR. SOMMERVILLE: I don't want to restrain you or inhibit you. 1163 MR. RATTRAY: Well, perhaps I may continue. If you would refer, Mr. Rogers, to Exhibit M.4.2. It's a summary of various IMO 18-month outlooks. 1164 MR. ROGERS: Yes, I have that now. 1165 MR. RATTRAY: If you'd turn to the second page which is an extract from the April 3, 2003 report. 1166 MR. ROGERS: I couldn't tell -- 1167 MR. RATTRAY: If you look at the bottom, sir, it says, "April 3, 2003 public," and at the top it says, "IMO 18-month outlook." 1168 MR. ROGERS: Yes. 1169 MR. RATTRAY: You'd agree with me that this is an extract of the report that you would have relied upon? 1170 MR. ROGERS: It looks like it. 1171 MR. RATTRAY: Well, if you subsequently determine that it is not, would you advise us? 1172 MR. ROGERS: Yes. 1173 MR. RATTRAY: Thank you. You'll note that in this report, they describe at section 2.1: 1174 "The Bruce A units, together with other additions, are added to the installed resources as they come into services described in section 2.4." 1175 Correct? 1176 MR. ROGERS: Sorry, could you say that again, please. 1177 MR. RATTRAY: I'm looking at section 2.1 and they note that: 1178 "The Bruce A units, along with other additions, are added to the installed resources as they come into service as described in section 2.4." 1179 MR. ROGERS: I'm just looking at section 2.4. 1180 MR. RATTRAY: Well, I was reading from 2.1, sir, and it's making the reference to 2.4. But would you agree with me that it says that Bruce A units are added? 1181 MR. ROGERS: As I read 2.1, the second paragraph: 1182 "The capacity of style generation resource in table 2.1 does not include Bruce A nuclear units which are currently in a laid-up state." 1183 MR. RATTRAY: It carries on and states: 1184 "Bruce A units, together with other additions, to generating capacity identified to the IMO via the connection assessment and approval process are added to the installed resources as they come into service as described in section 2.4." 1185 MR. ROGERS: Okay, yes, I'm with you. 1186 MR. RATTRAY: Okay. We go to 2.4, which is the next page over. Are you with me, sir? 1187 MR. ROGERS: Yeah, I am. 1188 MR. RATTRAY: At the bottom of the page it notes that there really are two scenarios, and this is the rationale, Mr. Chairman, as to why I wanted to know what date he was using for the restart. You have a reference resource scenario where they come into service on the dates indicated, and then you have a delayed resource scenario. Which of these scenarios did you rely upon, sir? 1189 MR. ROGERS: I would have to go back specifically, but I'm pretty sure we relied on the reference scenario. 1190 MR. RATTRAY: All right. 1191 MR. ROGERS: If we had this whole report, we could probably see a number of other proposed projects that were also supposed to come on line as high-efficiency merchant cogens. 1192 MR. RATTRAY: I appreciate that, sir. My questions were focused on the nuclear units. I appreciate you restricting yourself to the questions and we'll get through it much, much faster. 1193 MR. ROGERS: Okay. 1194 MR. RATTRAY: If you go back to the summary I prepared for you at the front of Exhibit M.4.2, you'll notice that as they quarterly updates are provided, that there's a certain amount of slippage with the return to service. 1195 MR. ROGERS: Yes. 1196 MR. RATTRAY: And, in fact, by the time you get to September 24, 2003, Pickering A unit 3: 1197 "It's assumed now that Pickering A unit 3 will not be synchronized to the grid during the time frame of this report, i.e., prior to March 30, 2005." 1198 MR. ROGERS: That's what it reads. 1199 MR. RATTRAY: Well, do you dispute that, sir? 1200 MR. ROGERS: I wouldn't dispute the IMO's judgment because I'm not in a position to judge whether they will or not. 1201 MR. RATTRAY: But you're not challenging that that was the IMO's judgment? 1202 MR. ROGERS: Subject to this being accurate, yes. 1203 MR. RATTRAY: Well, this material was provided to you in advance with extracts from the various reports. I understood from your comments earlier that you don't take issue with it? 1204 MR. ROGERS: That's correct. 1205 MR. RATTRAY: Okay. So from April 30, 2002, moving to the update of September 24, 2003, we now have an entire unit falling off the chart in terms of coming back in the 2004 season. 1206 MR. ROGERS: That's correct, which would be the Pickering A unit 3 which leaves a total of 2,040 megawatts that would come back. 1207 MR. RATTRAY: Well, not nuclear units, sir. 1208 MR. ROGERS: I'm sorry. The total that will be coming back on according to the September 24th are 500 under Pickering A. When you move down to -- Bruce A, 770, at each of those units. If we add that up, the total is 2,040 megawatts coming on prior to the 1st of January, 2004, at least according to what I see, with a 500 megawatt delay over and above that at Pickering A unit 3. 1209 MR. RATTRAY: Yes. And if you track through the Bruce A units, what do you note about it, other than there's, again, significant slippage? You have the report of April 3, 2002. They're coming back on the dates indicated. In March 2003, they're to be back in June and April of 2003. In June, we're told they'll be back in August and July. In September, we're told it will be back in November and October. 1210 MR. ROGERS: I see what you're saying. In between June and September, I'm trying to remember the actual date, but we had a blackout. Now, whether that blackout would, in fact, influence the pressure to bring these nuclear units on faster and to meet their target dates, my expert judgment says that it would. So there is a pattern that I'm looking at on the page; there is a reality check that I would offer in the real world that supports that the IMO should be accurate. Whether they will or won't, time will tell. 1211 MR. RATTRAY: Well, in terms of a reality check, isn't it fair to say that there have been ongoing delays in the return to service of the Bruce A units? 1212 MR. ROGERS: Yes, that's fair. 1213 MR. RATTRAY: And that your present 2004 forecast, number 1, did not include the delay in the return to service of Pickering A? 1214 MR. ROGERS: It didn't need to because, I will reiterate, with 2,040 megawatts of nuclear and in the forecast 1,220 megawatts of new merchant, you don't need another unit in order for the backing up the merchant plant. That's a conclusion that I draw from my evidence, and that's what I've said before. 1215 But we didn't know at the time that the Pickering A unit 3 would be left out. We do now. We don't have the ability to change our forecast from the blue-page update point of view. Would I change it as an expert because I know it's now down? It doesn't matter to my mix because, in fact, there's far more megawatts from the other three that are going ahead from a nuclear point of view, coupled with the new merchant cogens, it doesn't impact my forecast for 2004, blue going forward. 1216 MR. RATTRAY: That's assuming, sir, that the nuclear units at Bruce adhere to the schedule? 1217 MR. ROGERS: That's correct. 1218 MR. RATTRAY: And you concede the point that there has been significant slippage in the schedule? 1219 MR. ROGERS: I see the point. 1220 MR. RATTRAY: And you concede that's a risk that would impact on your forecast? 1221 MR. ROGERS: It's a risk that would contribute to. But, I've said it before, I won't repeat myself, there are several other factors that would factor in. This was one. And I would concede that by this pattern, it appears as though there's some question whether those nuclear units will be back. Whether they will or not remains to be seen. 1222 MR. RATTRAY: Since you've raised the issue of other factors in the electricity market, what other factors did you incorporate in your assessment, other than your stated belief that you will have these new high-efficiency gas merchant plants coming on line? 1223 MR. ROGERS: Stronger than a belief, we have committed contracts in place for all of the units that represent the 1,068 10(6)m3. So it's my belief and there's a contractual commitment that there's 1,220 new megawatts of high-efficiency cogeneration coming on either by or early in the first quarter of 2004. The nuclear units, we've gone over all of that. 1224 The third factor is you'd have to get past all of those new high-efficiency alternatives to have the oil-fired merchant cogen run, and right now, I checked the number, based on the discussion I had before, we are US$1 out of the market against oil in 2004 on our forward curves. We were 80 cents, and these are US, 80 cents out of the market in 2001. So even if we were able to dispatch, we don't expect we'd be able to place gas into the fuel mix at the existing merchant plan. 1225 MR. RATTRAY: So those are the factors that you considered in your assessment of the electricity market? 1226 MR. ROGERS: Those are the major factors, that's correct. 1227 MR. RATTRAY: I take it then you did not consider generator D rates? 1228 MR. ROGERS: I'm familiar with the fact that there are practices to D rate, but I'm not aware of those. That they are material? Looking through the document, I saw numbers in the order of 200 megawatts or less. I see that as lost in the rounding of the discussion. 1229 MR. RATTRAY: You didn't incorporate it, sir, did you? 1230 MR. ROGERS: I didn't think it was significant. 1231 MR. RATTRAY: All right. Generator outages, did you incorporate that? 1232 MR. ROGERS: Just let me be clear. Are you asking me, back in April of 2002, whether we incorporated generator outages? 1233 MR. RATTRAY: I asked you just a minute ago sir, to list the factors that you considered in assessing the demand for gas-fired electricity. We were looking at the introduction of new units, nuclear units. You referred to new high-efficiently gas plants coming on-stream. And now I'm going through a number of factors which, from your evidence, you have not considered or incorporated into your forecast. You've conceded you did not consider generator D rates. 1234 Now I'm asking, did you specifically consider and incorporate in your forecast generator outages? 1235 MR. ROGERS: No. 1236 MR. RATTRAY: Did you consider generator limitations due to transmission constraints? 1237 MR. ROGERS: I'm not sure what that is so, no. 1238 MR. RATTRAY: Did you consider lower hydroelectric production due to lower water levels? 1239 MR. ROGERS: I didn't feel we could predict the rain so it could have been higher or lower. 1240 MR. RATTRAY: So the answer would be you did not consider it? 1241 MR. ROGERS: We did not because it's a balanced risk, in our opinion. Whether you have a lot of rain, a lot of water, you have not much rain and not much water, so we didn't consider. 1242 MR. RATTRAY: You're not familiar with the concept that it could take several years for water basins to replenish from lower than average rainfalls? 1243 MR. ROGERS: I think we're getting into a lopsided point of view here. There's also the supply side or the demand side of electricity, maybe you're going there. But you have to look at the mix between supply and demand, just as we look at the spread between the gas price and the oil price. 1244 In my opinion, the IMO is charged with looking forward at the spread between electricity demand and the demand for electric generation. That's what we looked at. And we let the IMO do their magic behind the scenes because we're not experts. Based on those overall differentials and requirements for supply and demand of electricity going forward, we then looked at that and made a judgment call based on that, that we were correct and accurate in the way we forecasted. 1245 MR. RATTRAY: All right. So you didn't consider the water levels. Did you consider lower coal production from coal-fired electric generation plants as a result of the imposition of environmental caps? 1246 MR. ROGERS: We have been working with the coal plants on that, and the projects that we have been promoting have been unsuccessful against other alternatives to control emissions, so no. 1247 MR. RATTRAY: No. Now, in terms of demand, one of the factors you mentioned earlier was that you were concerned about the spread between gas prices and alternative fuels. 1248 MR. ROGERS: That's correct. 1249 MR. RATTRAY: You've also testified in your prefiled evidence that this customer group consists of large, sophisticated consumers? 1250 MR. ROGERS: That's right. 1251 MR. RATTRAY: Yet you have not considered in developing your forecast whether or not these customers have hedged their exposure to volatility in gas prices? 1252 MR. ROGERS: I would offer that, with all of our large customers, they do not necessarily take us inside of their camp and show us their hedging procedures or how they run their commercial operation. 1253 MR. RATTRAY: Fair enough, sir, but you didn't consider it or incorporate it into your forecast? 1254 MR. ROGERS: We didn't have it, so we didn't use it. 1255 MR. RATTRAY: Exactly. Did you consider the role that imports have played and continue to play in Ontario's electricity market? 1256 MR. ROGERS: I would refer you back to my answer that the IMO would do that and the mixture between supply and demand is what we count on, not the individual component parts. 1257 MR. RATTRAY: But you would rely upon the IMO's 18-month forecast and report? 1258 MR. ROGERS: Yes. 1259 MR. RATTRAY: Sir, if you'd turn back to the exhibit that we've already referenced, Exhibit M.4.2. Go to the extract from the April 3, 2002, at page 5 of 30, which is the fourth page in of this bundle, sir. There's a table 2.3, summary of available resources. 1260 MR. ROGERS: Okay. 1261 MR. RATTRAY: And total reduction in resources is note 4, the variety of scenarios set out there, and they review some of the constraints I've just asked whether or not you incorporated. So, obviously, you didn't incorporate these into your considerations: The sum of generator de-ratings, planned generator outages, to say nothing of forced generator outages, limitations due to transmission interface constraints, allowances for non-utility and hydroelectric generation production below rated capacity. 1262 MR. SOMMERVILLE: Could you slow down, please. 1263 MR. RATTRAY: I'm sorry, Mr. Chairman. 1264 Would you like me to repeat that, Madam Reporter? I referred you to note 4, these reductions represent, under each of the two scenarios, the sum of generator deratings, planned generator outages, generation limitations due to transmission interface constraints, and allowances for non-utility and hydroelectric generation production below rated capacity. 1265 MR. ROGERS: What I would suggest that we do in terms of the whole report, we would read the whole report. What I would suggest we do is give an undertaking, we'll go back and review how we interpret the report and we will -- I don't have that knowledge right here with me. We received this a day or so ago so we didn't have a chance to go all the way back through everything. 1266 MR. RATTRAY: Well, sir, I appreciate your offer, but frankly I have your evidence already that you did not consider these various factors that I just reviewed with you. It's not necessary to take your undertaking. 1267 MR. ROGERS: Okay. 1268 MR. RATTRAY: If we turn over to the next page, which is an extract from March 25, 2003, if you look at the heading, "Weather Impact," it notes the possibility of extreme weather conditions and there could be requirements for between 2,100 megawatts and 3,600 megawatts of electricity imports at the time of the weekly peak, and it notes that should we get increased generation capacity, this would decrease the reliance on electricity imports. 1269 In other words, sir, it's implicit in the report that we are relying on imports. 1270 MR. ROGERS: My understanding is that, going forward, the goal of the IMO and the government will be to reduce the dependance upon imports. 1271 MR. RATTRAY: Well, that may be the goal, sir, but we're not looking years down, we're looking at your forecast for 2004. And the IMO's forecast as of March 2003 notes a reliance on imports. That was not factored into your consideration, was it? 1272 MR. ROGERS: We did not take the component parts of the IMO forecast, take it down and do the detail of analysis that you're asking me questions on, that's correct. 1273 MR. RATTRAY: All right. If you turn over to the June 24 extract of the IMO's 18-month extract, and if you look at the second last paragraph, it notes: 1274 "There have been some updates to the generator outage schedule since the last published report resulting in a few weeks with higher available resources but with a majority of weeks having lower available resources." 1275 Have you found that reference, sir? 1276 MR. ROGERS: Yes, I'm looking at it. 1277 MR. RATTRAY: Now, I take it you didn't incorporate that into your forecast either, did you? 1278 MR. ROGERS: We don't forecast week to week, so no, we wouldn't have. 1279 MR. RATTRAY: Well, no, and you didn't include it in your update. 1280 MR. ROGERS: Because we wouldn't look at week to week. The other thing we do do is talk to the customer, and they give us information. So this is not the only thing that constitutes the way that we forecast, which I think is important. With all 76 customers, including this one large customer, we have a conversation with them as well so that we use this as a directional document to underpin it. We do also have discussions with the individual commercial people within the customer. 1281 MR. RATTRAY: I appreciate that, sir. 1282 Now, in terms of imports, given that you did not specifically consider their impact in your forecast, I take it you didn't take into consideration that the return to various resources, including the new gas-fired generation and nuclear plants, may well not displace Ontario-based generation but might displace, in fact, a reliance on imports. 1283 MR. ROGERS: Based on the fact that they are both higher efficiency and lower cost, I can't imagine that they would displace a higher, less-efficient, higher-cost merchant plant in a dispatch stack. That intuitively does not make sense to me. 1284 MR. RATTRAY: No. They may come into the stack at a lower level, but it's not whether they come into the stack below the existing merchant gas/oil facility, but whether or not the gas/oil facility continues to operate. 1285 MR. ROGERS: I did look at that on the various quarterly reviews, and on each and every one of them, particularly the last one out, which is September, it will support the fact that, on the dispatch stack, which we'd be happy to produce, at least the one we used and the order in which they would be dispatched, and in each and every case, that would be the last unit dispatched. And remembering, even if it was dispatched, we would have a disadvantage against oil and probably not run. That is the most important factor. 1286 We could debate the availability, and probably you will, as a lawyer, but we should not forget that we are a dollar out of the market, U.S., on the forward curves from the competitive ability to compete for that business. So even if the plant were available, which we still contend it is not for a number of reasons, you would have to beat -- you would have to reverse the relationship between oil and gas. 1287 MR. RATTRAY: And, again, that's without taking into consideration environmental matters and environmental caps and constraints on coal and/or oil-fired generation. 1288 MR. ROGERS: What we were told, unless the government is going to change it, each and every customer runs their plants independently, without an overriding emissions plan to run coal and the plant. Now, if that's true, and it's different than the IMO approach, then I'm not aware of that. 1289 MR. RATTRAY: So you're not aware that my client, Ontario Power Generation, is specifically subject to environmental restrictions? 1290 MR. ROGERS: Certainly, they are. But in the past, before the market opened, I know, in fact, if we go back into 2-01 and 2-02 that they did burn the collection of plants under one plant and managed their emissions that way. But I also know that when the market opened, the understanding that we had was that they would no longer do that because, under the IMO construct and framework, they were to run independently. So if that is new news, I didn't have it at the time. 1291 MR. RATTRAY: Thank you. 1292 If you'd turn to page 6 of your prefiled evidence, you're referencing existing independent power producers. You start off your paragraph at line 7: 1293 "It continues to be --" 1294 MR. ROGERS: Which document? 1295 MR. RATTRAY: That's your prefiled evidence, Exhibit C.1, tab 2. 1296 MR. ROGERS: Okay, thank you. 1297 MR. RATTRAY: At page 6, sir. Do you have that? 1298 MR. ROGERS: I will shortly here. Yes, I've got it. 1299 MR. RATTRAY: Do you see the heading "Existing Independent Power Producers"? 1300 MR. ROGERS: Yes, I've got that. 1301 MR. RATTRAY: You started your evidence by stating: 1302 "There continues to be considerable uncertainty about the operations of the 11 IPPs." 1303 MR. ROGERS: Yes, that's correct. 1304 MR. RATTRAY: And you carry on in that paragraph and reach the conclusion that you: 1305 "... expect these PPAs for some, if not all, to be renegotiated and result in lower gas demand." 1306 My question for you is: How, given in the space of a single paragraph, do you go from stating that there is considerable uncertainty to concluding that there's lower gas demand? 1307 MR. ROGERS: If you -- if the power plants are renegotiated down, which is our understanding that it would be, not up, because the embedded costs of these plants is higher than the available other forms of electricity generation, then the option would be to buy them down because they were negotiated in the '80s at a time when -- for 20-year contracts, when there was a time that people felt they needed incremental new gas cogen. So we know, and we are told specifically by independent power producers as late as this week, that in fact this is the case and could happen. And the probability is going up. So I stand by the evidence. 1308 MR. RATTRAY: Well, your evidence, with all respect, is inconsistent. There continues to be "considerable uncertainty," your words, and then you conclude in the same paragraph, "would result in lower gas demand." I guess I'm putting to you: What is it? Is there uncertainty or not? 1309 MR. ROGERS: Okay. There is certainty today that the oil and gas prices are in favour of oil. And this is the way we forecasted it. We forecast that it would be -- let me back up. We -- this is the white page? Sorry. This is the white page. 1310 At the time the white page was derived, which was in the summer of 2002, we had no way of knowing in 2004 whether, in fact, as the market opened, these contracts and independent power producers would, in fact, be restructured and bought down by that arm of the new market opening -- the financial arm. And so we only had four of our contracts protected with minimum takes for multiple years. The other seven were year to year. We had no idea or no way of knowing whether or not they would, in fact, be renewed. So we did put in base amount in spite of that which we feel balanced the possibility of whether they would or wouldn't be renewed. That is what the interpretation of that particular paragraph and the intent of it was trying to say. 1311 In fact, if you look at my blue-page evidence, you will find that we have adjusted them back up because, in fact, we know now that we have contractual protection through 10 months of 2004, and we only are posed for the last two months of 2004, which we have left in as a downward adjustment. Why? Because, in fact, the customers are telling us that the probability of that is going up. 1312 MR. RATTRAY: I'd like to turn now, sir, to Exhibit M.4.3. 1313 MR. ROGERS: Sorry, sir? 1314 MR. RATTRAY: Exhibit M.4.3, which is a summary sheet of volume actual versus forecast. Again, this document was provided to you and it's largely derivative of your prefiled evidence and answers to interrogatories, and then it summarizes actual and forecast volumes for rate 25, M7 firm, and total contract volume for the years 1999 through to 2002. 1315 MR. ROGERS: Yes, I have it. 1316 MR. RATTRAY: Do you dispute those numbers, sir? 1317 MR. ROGERS: Just to make sure, you're looking at the volume, not the revenue? 1318 MR. RATTRAY: I'm looking at volume. 1319 MR. ROGERS: Okay. The numbers that you have listed on the page as they were lifted from the evidence are correct. 1320 MR. RATTRAY: Yes. There's no corrections that are required to them? 1321 MR. ROGERS: No. 1322 MR. RATTRAY: All right. And the only thing that OPG added was to set out the percentage calculation of the variance between the forecast amount and the actual amounts, and I take it you don't dispute those calculations? 1323 MR. ROGERS: The only issue I have is with the M7 contract, because if you put the M7 and T1, which nullifies the rate-switching between those two rates, together, instead of a four-year average variance under M7 firm standing alone, it reduces to minus 4 percent. In fact, the numbers for '99 through to 2002 for variance would become zero, minus 1, minus 16 because of the bad year with high gas prices, and 2 percent. So if you take the rate-switching out, the accuracy of the M7 is virtually bang on. 1324 MR. RATTRAY: Well, if you go to the total contract volume, the variance certainly is reduced compared to the variance that we see in the M7 firm and the R25. 1325 MR. ROGERS: I've explained the variances for those and the reasons for those. I don't think it's necessary to repeat those. I could repeat why the variances are as they are, but it's already on the record. 1326 MR. RATTRAY: No, no, I don't want you to repeat all that. I'm simply noting that, in terms of the individual rate categories, R25, there's a huge variance. In 1999, the variance was 104 percent. 1327 MR. ROGERS: Right. Rate 25, I agree there's a large variance. We've already talked about the reasons why. M7, as it stands alone, is not a good reflection of the truth because the M7 and T1 need to be put together and remove the switching in order for you to get a clear picture of what the change -- 1328 MR. RATTRAY: But the M7 customers, sir -- 1329 MR. PENNY: Hang on a minute. Mr. Rattray, could you let Mr. Rogers finish before you cut him off, please. 1330 MR. ROGERS: The M7 and the T1, as you can see from my evidence, basically lays out the migration of a number of our large bundle-T customers to T1 service, and in fact, we have a number of them, three of them very large, that we have just signed contractual commitments starting November of 2003. So we have underpinning contracts that support this. And when you do that, you take out the rate-switching, then the M7 and T1, which is a volumetric historical comparison, is absolutely bang on. If you don't, you get a warped picture of that M7. I will grant you that the rate 25 is overrun, and we've explained that. I'd be happy to go through that one more time, on the rate 25, if you like. 1331 MR. RATTRAY: We have your explanation, sir, and the numbers, I think, speak for themselves in terms of the significant variance between them. 1332 But in terms of the customers who are charged on the basis of the M7 firm rate, as much as you would like to lump them in with the other rate that you've referenced, the T1 rate -- 1333 MR. ROGERS: T1, semi-unbundled. 1334 MR. RATTRAY: -- the fact remains that with respect to the M7 firm rate, there still is a significance variance between the volume forecast and the actual amounts. 1335 MR. ROGERS: I would offer, if you combine the M7 and T1, there isn't; that the main driver in it is the rate-switching. And if you take that out - we've done it and, as I said, I'd be happy to provide it - when you do, the differential shrinks down to 1 or 2 percent, and in one case minus 16, the year that the gas price was so high. 1336 MR. RATTRAY: Mr. Rogers, I take it you would then agree with me that for at least the last four years, rate 25 has consistently underestimated the volume? 1337 MR. ROGERS: I would put it a different way, that rate 25, driven primarily by the oil/gas-fired merchant plant, has overperformed compared to what the parameters were that we used for the forecast. And we explained that. 1338 MR. RATTRAY: Well, let's come back to my question: It has consistently underestimated the volume. 1339 MR. ROGERS: I've explained all the reasons why. But the numbers speak for themselves, yes. 1340 MR. RATTRAY: Would that be yes, sir? 1341 MR. ROGERS: Yes. 1342 MR. RATTRAY: Thank you. You would agree that for the last four years, the R25 has significantly underestimated the volume. Not only has it been consistently, it's a significant amount. 1343 MR. ROGERS: I would agree that the variance from the forecast to the actuals has been large. I would not agree that the forecast was inaccurate. So whichever way you want to look at it. 1344 MR. RATTRAY: Turning to the M7 firm, you would agree that for the last four years, the M7 firm has, on average, underestimated the volume? 1345 MR. ROGERS: I'll try it one more time. The M7 and T1, if you put the rate-switching together, it's been very accurate. If you look at our ability to predict the allocation between the two, we've had ongoing discussions with those customers that told us that they were looking to migrate to T1. I've just said that we have the contract commitments from them now that tie them to the 2004 forecast, and the reason for that -- and the remaining M7 customers are lower load-factor customers. 1346 People are migrating to T1 because Union's balancing requirements are changing. People are looking at that and saying that they are now prepared to take on the risk of going to a semi-unbundled daily balancing and therefore are leaving other customers, bundled-T rate 7s, who aren't willing to take that risk to remain in the M7 grouping. And the load factor is dropping because the people that are staying would not have the qualifications to move. 1347 So that's why the two have to be looked at together or you get a very warped point of view. 1348 MR. RATTRAY: But you don't dispute that on the numbers as they relate to the M7 firm, that on average you've consistently and significantly underestimated the volume. 1349 MR. ROGERS: If we leave information out that's pertinent and we do it the way you've done it, the numbers speak for themselves, that's true. If you complete the picture, it's not. 1350 MR. RATTRAY: I'd ask that you now turn to Exhibit M.4.4, which is the revenue actual versus forecast. 1351 MR. ROGERS: I have that one. 1352 MR. RATTRAY: Do you have it, Mr. Rogers? 1353 MR. ROGERS: I do. 1354 MR. RATTRAY: Now, again, we've summarized your prefiled evidence and answers to various interrogatory responses in relation to R25 interruptible and M7 firm. Do you dispute any of these numbers, sir? 1355 MR. ROGERS: I need to clarify, particularly on rate 25. The problem we have there is that the -- and it's our problem, but it's the rates, as they are reported, include the gas commodity components; and if we remove that factor for the rate 25, in fact, the numbers are dramatically different. And I can give the numbers, I'd be happy to produce it or supply it, but the numbers that are up top which are extraordinarily huge drop down into numbers that are more realistic, because you can't really count the gas commodity. It is not part of our delivery revenue. We make no money on it. We pass it through. It's not part of our earnings picture. We pass it through to the customers at cost. When you do that, you get a much clearer picture. Granted, the actual is still higher than the forecast, but the extraordinary numbers that come up on the top line for rate 25 are corrected to give a clearer picture. 1356 MR. RATTRAY: Well, I would ask for your undertaking to provide us with the numbers for R25 with the commodity extracted from it. 1357 MR. ROGERS: We should do that for M7 as well. There's a minor component there as well. 1358 MR. RATTRAY: All right. If that could be the next undertaking. 1359 MR. MORAN: Mr. Chair, Undertaking N.4.8 is an undertaking to restate Exhibit M.4.4 with the removal of the commodity component for both rate 25 interruptible and M7 firm. 1360 UNDERTAKING NO. N.4.8: TO RESTATE EXHIBIT M.4.4 WITH THE REMOVAL OF THE COMMODITY COMPONENT FOR BOTH RATE 25 INTERRUPTIBLE AND M7 FIRM 1361 MR. RATTRAY: So on that basis, sir, should be pull from the response you provided at Exhibit J.17.15, which is a response to our interrogatory asking for a forecast and actual numbers for volume, should we be pulling out, then, all of these commodity numbers, including the rate 25 and M7? 1362 MR. MORAN: Sorry, what was the reference? 1363 MR. ROGERS: I think we might be mixing a couple of things. The revenue, my J.15 -- sorry -- 1364 MR. RATTRAY: J.17.15. 1365 MR. ROGERS: J.17.15 is volumes only. What we just talked about were revenues for the undertaking. 1366 MR. RATTRAY: Well, when I look at my J.17.15 -- 1367 MR. ROGERS: Sorry, there is another part that I don't have here with me. What's the page number? 1368 MR. RATTRAY: Well, you can look at any number of them. Look at, say, page 7. 1369 MR. ROGERS: Okay, sorry. So 7 of 11? 1370 MR. RATTRAY: Yes. 1371 MR. ROGERS: Okay, I've got it now. Sorry. 1372 MR. RATTRAY: So if I understand your evidence today, in contrast with all the materials you filed and your response to this interrogatory which stated that it was a summary of gas sales, delivery and transport, you're saying that there's a commodity hidden amongst your total revenue. 1373 MR. ROGERS: Incorporated, and, as I understand it, it's the way that the accounting people have to report it for regulatory purposes. I don't do that so that's why it's -- that's my understanding of the way that it's done. We can unravel it and show it to you another way, and we'll undertake to do that. 1374 MR. RATTRAY: All right. But based on the numbers as you've provided them to the Board in your filed evidence and your response to the interrogatories, you don't dispute the calculations we've made with respect to R25 and M7? 1375 MR. ROGERS: In order for the way that it's reported to regulatory which is flawed because the commodity is included, yes. 1376 MR. PENNY: I'd note, Mr. Chairman, that at the top of that page and the other pages, it makes it quite clear that it is a summary of gas sales, delivery and transportation for contract customers. 1377 MR. SOMMERVILLE: Mr. Penny. 1378 MR. RATTRAY: Thank you, Mr. Penny. 1379 Earlier, Mr. Rogers, you'd given an undertaking to perform an analysis to determine revenue sensitivity to increases in volume. 1380 MR. ROGERS: Yes. 1381 MR. RATTRAY: And I would ask that you expand that undertaking to perform a sensitivity analysis for M7 firm and R25. 1382 MR. ROGERS: Excuse me. I think we can do it. I'm just trying to clarify. I believe we should take the undertaking. We don't do those calculations ourselves. The only issue on rate 25 may be the rate -- we could use the average -- I'm just trying to think of what rate to use, because the only way to do is to take the volume and multiply it by a rate. Rate 25 is negotiable and has a variable component to it. So we could use the average for 2004 as it was incorporated, which I think is probably the only reasonable way to do it. 1383 MR. RATTRAY: Well, if you're going to make reference to the average, it would be useful for the Board to also see the maximum, because there may be a customer unlucky enough to be saddled with the maximum rate. 1384 MR. ROGERS: They may be, but they also probably burned out -- there are customers out there at the maximum rate who have no minimum contractual takes, and so if you multiply zero times the maximum number, you still get zero. But we can -- so we can show the range, and then what I would offer is we should show the number that is the average, because we don't give out customer confidentiality, we don't hand out individual component rates to the public. And that is the reasonable way to give an incremental response. Paul? 1385 MR. GARDINER: Yeah, I believe that's correct. 1386 MR. ROGERS: So based on that, we would use the average for 2-04, and we would show the range, it's already in the rates, already filed, and we would undertake to answer that. 1387 MR. RATTRAY: Is it a weighted average? 1388 MR. ROGERS: I don't do the calculation. It's done by our administrative group so ... 1389 MR. RATTRAY: Would you make that clear in your response? 1390 MR. ROGERS: Yes, we will. 1391 MR. RATTRAY: If you would turn now, sir -- 1392 MR. SOMMERVILLE: We need to define that undertaking. Mr. Rattray, perhaps you could do so. 1393 MR. RATTRAY: I will endeavour to do so, Mr. Chairman. 1394 It was a request to expand the prior undertaking given to Mr. Thompson to perform a sensitivity analysis to determine revenue sensitivity to increases in volume, and I would simply ask that that analysis be performed specifically for rate categories M7 firm and R25. 1395 MR. SOMMERVILLE: And there is a -- 1396 MR. MORAN: This would be an addition to Undertaking N.4.2, Mr. Chair. 1397 MR. SOMMERVILLE: Fair enough. We'll wrap it into Mr. Thompson's undertaking. 1398 MR. RATTRAY: That would be fine, Mr. Chairman. 1399 MR. SOMMERVILLE: As I understand it, there was a qualification to the effect that because the rate -- the rates under this rate class are -- M7 rate class are negotiated, that an arithmetic average rate will be used to represent the rate governing the volumes. 1400 MR. PENNY: That's largely correct, Mr. Chairman, except it's the rate 25 that's the range, not the M7. 1401 MR. SOMMERVILLE: I'm sorry. 1402 MR. ROGERS: Yes. 1403 MR. RATTRAY: And the answer will further specify the nature of the average. 1404 MR. SOMMERVILLE: Fair enough. That is, whether it's weighted or not. 1405 MR. RATTRAY: Yes. 1406 MR. SOMMERVILLE: Is that clear to everybody? 1407 MR. ROGERS: Yes. 1408 MR. SOMMERVILLE: Thank you. 1409 Thank you, Mr. Moran. 1410 MR. RATTRAY: Mr. Rogers, if you would now turn to Exhibit M.4.5. 1411 MR. SOMMERVILLE: I take it we're getting to the end, Mr. Rattray? 1412 MR. RATTRAY: Momentarily, Mr. Chairman. 1413 MR. ROGERS: Unfortunately, these weren't numbered exhibits. 1414 MR. SOMMERVILLE: This is the one entitled, "Additional Revenue for Each 100,000 10(3)m3." 1415 MR. ROGERS: I have it now. 1416 MR. RATTRAY: Do you have it, Mr. Rogers? 1417 MR. ROGERS: Yes, I just didn't have it numbered. But, yes, I have it. 1418 MR. RATTRAY: This represents calculations performed by my client, Ontario Power Generation, using the figures as set out in your prefiled evidence and in your answers to interrogatories, and we've performed a sensitivity analysis. Do you dispute those calculations using the numbers as set out in the evidence? 1419 MR. ROGERS: I think this will have the same issue of the commodity block, so we may need to fix everything and then recalculate this accordingly, would be my take on how to do this. 1420 MR. RATTRAY: Yes. But in terms of the numbers as reported, you don't dispute the calculation. I understand your concern that you may need to pull out commodity. 1421 MR. ROGERS: The answer is yes, subject to the flaw that commodity introduces, the major flaw. The answer is yes. 1422 MR. RATTRAY: Thank you, Mr. Chairman. Those are my questions. 1423 MR. SOMMERVILLE: Thank you, Mr. Rattray. 1424 Just to be clear on this point, is it your intention, Mr. Penny, to reproduce this schedule with the commodity component extracted? 1425 MR. PENNY: Well, it wasn't because Mr. Rattray didn't ask for it. But if somebody does ask for it, we can do that. 1426 MR. SOMMERVILLE: I heard Mr. Rogers volunteer to do that. 1427 MR. PENNY: But Mr. Rattray didn't take him up on it. If you would like us to do that, we will. 1428 MR. RATTRAY: I had understood, Mr. Penny, that that was being done. 1429 MR. PENNY: Fine. It is. 1430 MR. RATTRAY: With the chairman's indulgence, I would make that request if it wasn't clear to Mr. Rogers and to Mr. Penny. 1431 MR. PENNY: Consider it done. 1432 MR. SOMMERVILLE: So that the ambiguity isn't left. 1433 MR. MORAN: Mr. Chair, Undertaking N.4.8 would include a reference to Exhibit M.4.5, along with M.4.4. 1434 MR. SOMMERVILLE: Mr. Janigan, you're going to get your wish, you're going to get to come back tomorrow. 1435 MR. JANIGAN: I don't know if that was my wish. 1436 MR. SOMMERVILLE: I wasn't being entirely serious. 1437 We will adjourn until 9:30 tomorrow morning. Thank you. 1438 --- Whereupon the hearing was adjourned at 4:30 p.m.