Rep: OEB Doc: 12RX6 Rev: 0 ONTARIO ENERGY BOARD Volume: 1 24 JUNE 2003 BEFORE: R. BETTS PRESIDING MEMBER B. SMITH MEMBER F. PETERS MEMBER 1 RP-2002-0118 EB-2002-0332 2 IN THE MATTER OF the Ontario Energy Board Act, 1998, S.O. 1998, c.15 (Sched. B); AND IN THE MATTER OF a Notice of Intention to Make a Compliance Order under section 75 of the Ontario Energy Board Act, 1998. 3 RP-2002-0118 EB-2002-0332 4 24 JUNE 2003 5 HEARING HELD AT TORONTO, ONTARIO 6 APPEARANCES 7 PAT MORAN Board Counsel J. SIDLOFSKY Abitibi-Consolidated Inc. ANDREW LOKAN Power Workers Union MARY ANNE ALDRED Hydro One Networks RICHARD KING TransAlta Energy corp. 8 TABLE OF CONTENTS 9 APPEARANCES: [29] PRELIMINARY MATTERS: [40] ABITIBI-CONSOLIDATED - PANEL 1; GARTSHORE, SNELSON [133] OPENING SUBMISSIONS BY MR. SIDLOFSKY: [140] EXAMINATION BY MR. SIDLOFSKY: [232] CROSS-EXAMINATION BY MR. MORAN: [591] CROSS-EXAMINATION BY MS. ALDRED: [931] RE-EXAMINATION BY MR. SIDLOFSKY: [1402] QUESTIONS FROM THE BOARD: [1498] 10 EXHIBITS 11 EXHIBIT NO. 1.1: MATERIALS FILED BY ABITIBI-CONSOLIDATED IN SUPPORT OF THE COMPLAINT [105] EXHIBIT NO. 1.2: PRE-FILED EVIDENCE FILED FEBRUARY 28, 2003, BY ABITIBI-CONSOLIDTAED [107] EXHIBIT NO. 1.3: PRE-FILED EVIDENCE FILED BY HYDRO ONE ENTITLED "WITNESS STATEMENT" DATED FEBRUARY 28, 2003 [110] EXHIBIT NO. 1.4: DOCUMENT ENTITLED "ADMINISTRATIVE INSTRUCTION TO MANAGER, NORTHWEST DISTRICT, TITLE, 'OPERATIONS AGREEMENT BETWEEN ONTARIO HYDRO AND STONE CONSOLIDATED CORP., FORT FRANCES', DATED JANUARY 31, 1997 [382] EXHIBIT NO. 1.5: SPREADSHEET SHOWING CALCULATIONS THAT SHOW THE DIFFERENCE BETWEEN GROSS LOAD BILLING AND NET LOAD BILLING FOR THE ABITIBI COMPLEX [413] EXHIBIT NO. 1.6: EXCERPT FROM A FILING IN THE RP-1999-0044 PROCEEDING, ENTITLED "NET LOAD BILLING VERSUS GROSS LOAD BILLING" [569] EXHIBIT NO. 1.7: FIGURE 1: FORMS OF CONNECTION TO TRANSMISSION NETWORK [1261] 12 UNDERTAKINGS 13 UNDERTAKING NO. U.1.1: TO CONFIRM IF ABITIBI-CONSOLIDATED IS STILL AN INTERRUPTIBLE LOAD [697] UNDERTAKING NO. U.1.2: TO CONFIRM WHETHER ABITIBI'S CO-GENERATION IS BILLED ON A GROSS-LOAD OR A NET-LOAD BASIS [752] UNDERTAKING NO. U.1.3: TO REVIEW EXHIBIT 1.5 AND TO UPDATE IT, REMOVING INACCURACIES [1529] 14 --- Upon commencing at 9:30 a.m. 15 MR. BETTS: Good morning, everybody. 16 The Board is sitting today in the matter of application RP-2002-0118, transmission rate order compliance hearing, involving Abitibi-Consolidated Company of Canada and Hydro One Networks. 17 Before I go any further, can you all hear me at the back? 18 Thank you. 19 On April 30th, 2002, the Board received a complaint from Abitibi-Consolidated which alleged that Hydro One was not in compliance with section 19 of its transmission licence, which requires Hydro One to charge transmission rates only in accordance with its transmission rate. 20 The Board panel -- a Board panel comprised of members Zerker and Birchenough considered the complaint on October 8th, 2002, issued a notice of intention to make a compliance order to Hydro One Networks under section 75 of the Ontario Energy Board Act. 21 The compliance order would order Hydro One to comply with its transmission licence number ET-1999-0332. 22 On October 21st, 2002, Hydro One requested a hearing in this matter. Procedural Order No. 1 was issued on December 18th, 2002, setting out time lines for presenting lists of relevant documents and the issuance of and responding to interrogatories. 23 Procedural Order No. 2 was issued on May 23rd, 2003, setting the date of the oral hearing. 24 Letters requesting intervenor status were recently received from the Power Workers Union and from TransAlta Energy Corporation. 25 The Board will deal with those as preliminary matters. 26 It is the Board's intention to deal with this hearing, the hearing of this application today, and if necessary, tomorrow, and expects arguments to be received orally at the conclusion of the evidentiary portion of the hearing. 27 My name is Bob Betts. I am the presiding member in this hearing and joining me are fellow Board Members Mr. Brock Smith and Mr. Fred Peters. 28 May I have appearances, please. Yes? 29 APPEARANCES: 30 MR. SIDLOFSKY: Sir, my name is Sidlofsky, S-i-d-l-o-f-s-k-y, initial J; counsel for Abitibi-Consolidated Inc. 31 MR. BETTS: Thank you, Mr. Sidlofsky. 32 MS. ALDRED: Good morning. My name is Mary Anne Aldred, A-l-d-r-e-d, counsel this morning for Hydro One Networks. 33 MR. BETTS: Ms. Aldred, thank you. 34 MR. LOKAN: My name is Andrew Lokan, L-o-k-a-n, counsel for the Power Workers Union. 35 MR. BETTS: Thank you. 36 MR. KING: My name is Richard King. I'm counsel to TransAlta Energy Corporation. 37 MR. MORAN: Pat Moran, Board counsel. 38 MR. BETTS: And thank you, Mr. Moran. 39 And that's all the appearances. 40 PRELIMINARY MATTERS: 41 MR. BETTS: Under preliminary matters, first the Board would like to deal with, as mentioned earlier, the letters requesting late intervenor status by two parties, the Power Workers Union and I see Mr. Lokan is here. 42 Perhaps if we deal with that first. We have received two letters, an initial one followed by a more detailed one. Is there any further submission that you have for the Board's consideration? 43 MR. LOKAN: I think I would just make three brief points, and these are largely in the letter, so I am going to try and keep very brief and not repeat myself. 44 This proceeding is very much an outgrowth of RP-1999-0044, that's the main authority cited by both sides. The PWU was an active participant in that proceeding. 45 This proceeding also has some implications for the transmission code review proceeding, that's RP-2002-0120, and again, the Power Workers Union is an active participant in the transmission-code review. 46 The fact that there are some common or overlapping issues is recognized by AMPCO. Mr. Sidlofsky's partner, Mark Roger, put in a submission on transmission-code review commenting in great detail on this case, so I think it is recognized that what counts as embedded generation has some bypass implications. 47 Now, having said that, it is not the Power Workers' intention to in any way transform this into a parallel transmission-code-review type proceeding. It is just our intention to make, if we are allowed intervenor status, some brief submissions at the end without participating in the evidentiary portion in support of Hydro One. We would seek to be a very restrained intervenor. 48 The third point that we would make is that as the bargaining agent, the recognized bargaining agent for Hydro One, the financial implications of this case have implications for us as well, although in the larger scheme of things a couple of million dollars a year is not -- doesn't dominate Hydro One's revenue. Nevertheless, it is not an inconsequential sum, and to the extent that this has implications on the financial side for Hydro One, it has implications for the Power Workers as well, and for the ability of Power Workers-represented members to serve other Hydro One customers at the highest efficiency and lowest cost. 49 So those are the reasons why we believe it is appropriate that we be here as an intervenor, and as I say, we seek to be a restrained intervenor that participates only in closing submissions. 50 MR. BETTS: Thank you. 51 Ms. Aldred, we received a letter from you indicating your position with respect to one of the parties. Do you have any submission with respect to the Power Workers Union application? 52 MS. ALDRED: Yes, I do, and I'll be brief, and some of these submissions will overlap with what I have to say about TransAlta. But I would just note as a general proposition that this hearing is not a generic, in our submission, policy-based hearing, but it is a hearing that is based on a compliance issue and it involves whether Hydro One is properly applying the transmission tariffs to Abitibi, and as such, it is a hearing that really involves those two parties, and in our submission, those two parties alone. 53 And for that reason, we would oppose interventions, both by the Power Workers Union and also by TransAlta, and I'll speak further to TransAlta. 54 I do note on the Power Workers side that they have indicated they intend to be a restrained intervenor, so I am less opposed to that. 55 MR. BETTS: Thank you. 56 Mr. Sidlofsky, any submission? 57 MR. SIDLOFSKY: Sir, just one point of clarification. It wasn't my partner, Mr. Roger, who was acting or who is acting for AMPCO in the transmission proceeding; that is Mr. Fisher from Gowlings. 58 Aside from that, we had filed a letter with the Board late in the day yesterday. I am not sure the Board has a copy of our letter of yesterday afternoon. 59 MR. BETTS: I don't believe we have got that one, Mr. Sidlofsky. 60 MR. SIDLOFSKY: Sir, I do have copies here. 61 MR. BETTS: Thank you, that would be very helpful. 62 Are there sufficient copies for the other parties? 63 MR. SIDLOFSKY: I do have some, yes. I believe Ms. Aldred has ours. 64 MS. ALDRED: Yes, I do. 65 MR. SIDLOFSKY: And Mr. Lokan as well. I am not sure about Mr. King. 66 Sir, this letter largely reflects Ms. Aldred's comments. The difference is that Abitibi will not be opposing the requests for intervenor status from the Power Workers Union or TransAlta. 67 We are concerned, however, and Ms. Aldred has expressed that concern, that this not be turned into a parallel transmission-system-code review process. There are and there have been several submissions on the issue of transmission system bypass in that proceeding. That proceeding has been going on now for over a year. 68 Bypass of the transmission system can take on a number of forms. This is not a hearing about bypass. As Ms. Aldred indicated, this is a hearing about how the existing rate order is to be applied to an existing transmission customer that has generation embedded -- excuse me, generation in its complex that supplies that load with its electricity requirements. 69 There are several other methods of bypassing a transmission system and those are all being canvassed in the transmission-system-code proceeding. 70 My other concern with Mr. Lokan's letter is that it raises concerns about the potential financial impact of the Board's decision in this matter. 71 Now, first of all, we had filed additional material with the Board, including a spreadsheet, that was intended to illustrate an approximation of the impact on Abitibi of gross load billing as opposed to net load billing, and I'll explain those issues in my introductory comments. 72 But initially, Abitibi had estimated the impact at $2.8 million a year. They have now had a chance to look at their figures for the first 12 months since market opening. Their estimate of the difference between gross and net load billing is approximately $1.7 million. Probably still not insignificant from Mr. Lokan's viewpoint, but it is less than the original $2.8 million. 73 I am not aware of any evidence at this point that has been filed to indicate that the reimbursement of Abitibi of $1.7 million or the ongoing billing of Abitibi on a net basis, rather than a gross basis, will have any significant financial impacts on Hydro One or will affect their ability to, as Mr. Lokan puts it, meet the needs of its other customers with the maximum efficiency and at the lowest possible cost. 74 I am certainly not opposed to Mr. Lokan making submissions on that concern. However, I would note that there is no evidence to support the conclusion that the reimbursement of Abitibi and the net billing going forward would have a significant impact on Hydro One's ability to service its customers. 75 MR. BETTS: Thank you. Any further submissions on that specific request? And before the Board considers ruling on that, I would like to deal now, if I can, with the TransAlta request, and I'll look to Mr. King and ask if there is any further submission you would like to make to the Board beyond the points made in the letter? 76 MR. KING: I would just like to briefly reiterate that TransAlta has a very similar situation at its Sarnia plant with respect to download and Hydro One billing with respect to that load. 77 It isn't our intention to try that case here, but obviously the disposition of this matter, and how the Board deals with the phrases "embedded generation," how it disposes of what a transmission customer means, what a transmission delivery point means, has a huge impact on TransAlta's interests at the Sarnia site. 78 I disagree with the comment by Ms. Aldred that this is, in a sense, a litigation piece between two parties and has no broader public policy implications, I think for two reasons. The Board in deciding any matter has been given a public interest mandate and the objectives with respect to electricity are set out in section 1 of the OEB Act, and it is those guiding principles that the Board always has to have front of mind when it determines any matter. 79 And this case will be no different. It is why the parties before you in conducting their cross-examination and in making their final arguments will appeal to that public interest mandate, and indeed, how you decide the questions that I just mentioned, embedded generation, transmission delivery point and transmission customer, will have implications beyond Hydro One and beyond Abitibi. They'll have implications for a wide variety of participants in the electricity market in the province. 80 I would just point out one other thing, that the test for standing before the OEB is in section 23 of the rules of procedure, and it says that the person applying for intervenor status must satisfy the Board that he or she has a substantial interest. 81 That threshold has been typically very low. Almost without exception, parties seeking intervenor status have been granted intervenor status before this Board, and indeed, before most tribunals in the country. Boards, in a sense, don't strictly determine standing to sue or standing to intervene. They essentially determine, "To what extent are we going to allow this party to participate?" And TransAlta, as I said, won't be trying its case in this proceeding. I would ask that you grant me intervenor status and the ability to cross-examine, to a limited extent, the Hydro One panel and to make final submissions. 82 And I think those are my submissions. 83 MR. BETTS: Thank you. And are there any further submissions on that particular request? Ms. Aldred. 84 MS. ALDRED: Thank you. I would like to renew my opposition to this intervention request in that for the reasons that I have stated before, this is, in our view, very much a dispute between two parties. 85 TransAlta has not been involved in this issue, and has only very recently asked to be involved in this proceeding, and the outcome of this proceeding will be an order which will say either that Hydro One is complying with its licence vis-a-vis Abitibi or it is not. 86 In my submission, it will not directly affect TransAlta. This is, furthermore, a matter of some importance to Hydro One. It does involve compliance with our transmission licence and, in my submission, it is really not appropriate to let unrelated parties cross-examine about their own situations which are, in fact, not before the Board. TransAlta does not, to my knowledge, have a complaint before the Board about their billing situation in Sarnia. 87 Finally, I am concerned about the fact -- I would like to advert the Board to the fact that the Hydro One witnesses are not prepared to speak to the TransAlta situation. It is not before the Board, and they will not be prepared to speak to it, so I don't know what Mr. King had in mind when he talked about limited cross-examination, but I would just like to advert you to the fact that they have prepared today for the Abitibi case and not a TransAlta complaint. 88 Thank you. 89 MR. BETTS: Thank you. 90 Mr. Sidlofsky, anything further that you would like to comment on this application? 91 MR. SIDLOFSKY: Nothing further, sir. As I have said, we are not opposing either the Power Workers or the TransAlta intervention requests, subject to the comments I have already made on the scope of this proceeding. 92 MR. BETTS: Thank you. 93 [The Board confers] 94 MR. BETTS: The Board Panel will take a short break at this point, just to consider the submissions made, and this won't be sufficient time for anyone to get down and have a coffee, so I would ask those that intend to participate to stick around the room. Hopefully we will be back within 10 minutes. We will adjourn. 95 --- Recess taken at 10:00 a.m. 96 --- On resuming at 10:05 a.m. 97 MR. BETTS: The Board is prepared to grant intervenor status to both the parties requesting it under the terms that they have promised, which is, in the case of the Power Workers Union, in the form of submissions, and in the TransAlta, in limited questioning of the Hydro One Networks' panel and submissions to follow. And I am sure Mr. King will be limiting his cross-examination to the more general issues associated with the rate application rather than the specifics of the TransAlta matter -- no, sorry, of the Abitibi-Consolidated matter. 98 With that done, I would ask if there are any other preliminary matters that the Board should consider at this point. Mr. Moran? 99 MR. MORAN: Yes, Mr. Chair, there is a few items that need to be marked as exhibits. 100 There is the April 30th, 2002, complaint that was filed by Abitibi-Consolidated. 101 MR. BETTS: Mr. Moran, you are going to have to bear with us too. Our files are not particularly well organized, I have to apologize for that. So take your time in helping us with this. So that was -- 102 MR. MORAN: Yes, Mr. Chair, my understanding is that you would have two binders of material that was filed by Abitibi-Consolidated, and the first binder would be the set of materials that were filed in support of the complaint, and that is dated April 30th, 2002. 103 MR. BETTS: Thank you. 104 MR. MORAN: And that would become Exhibit 1.1. 105 EXHIBIT NO. 1.1: MATERIALS FILED BY ABITIBI-CONSOLIDATED IN SUPPORT OF THE COMPLAINT 106 MR. MORAN: The second binder of material contains the pre-filed evidence that was filed by Abitibi-Consolidated dated February 28th, 2003, and that would become Exhibit 1.2. 107 EXHIBIT NO. 1.2: PRE-FILED EVIDENCE FILED FEBRUARY 28, 2003, BY ABITIBI-CONSOLIDTAED 108 MR. BETTS: Thank you. 109 MR. MORAN: And the third item would be the binder of pre-filed evidence that was filed by Hydro One entitled "Witness Statement", and that would become Exhibit 1.3. 110 EXHIBIT NO. 1.3: PRE-FILED EVIDENCE FILED BY HYDRO ONE ENTITLED "WITNESS STATEMENT" DATED FEBRUARY 28, 2003 111 MR. BETTS: Thank you. 112 MR. MORAN: And it is dated February 28th, 2003. 113 Thank you, Mr. Chair. 114 MR. BETTS: Any further preliminary matters to be dealt with? 115 It is the Board's understanding, and I can see from the structure of the room that it is probably correct, that Abitibi-Consolidated will lead off with their case for a compliance order, presenting its witness panel first. 116 Mr. Sidlofsky, are you prepared to begin? 117 MR. SIDLOFSKY: Certainly, sir. 118 I should note we have just reorganized ourselves a little. Mr. Moran wanted to prevent me jumping up and giving my own evidence, so now you have our witnesses closer to you. I will, however, or I would like to, with the Board's indulgence, make an opening statement to try and explain a couple of issues that the Board is dealing with this morning. I expect I'll be about 20 minutes, and then I would go right into our direct evidence with our witnesses. 119 MR. BETTS: Okay, and perhaps before you do, if you could introduce your witnesses, we'll have them sworn in, and then we can go right on from there. 120 MR. SIDLOFSKY: I would be happy to, sir. 121 Our witnesses will be dealing with Abitibi's evidence as a panel. The first witness is Jim Gartshore; he is to my far left. Mr. Gartshore is vice president, engineering and energy of Abitibi Inc. He was the general manager of Abitibi's Fort Frances complex, the complex that we are dealing with today, from 1995 to 2002, and in fact, Mr. Gartshore has been the electrical superintendent and the manager of maintenance and engineering at the complex from 1977 to 2002. 122 Mr. Gartshore is an electrical engineer and he is registered as a professional engineer in the Province of Ontario, and he has been involved in the design, construction, start-up and ongoing maintenance of the Fort Frances co-generation facility in the Abitibi complex. 123 You'll hear that facility referred to variously as the Fort Frances co-generation complex or the Westcoast facility -- excuse me, the Westcoast facility or the Fort Frances co-generation facility. 124 The second witness on Abitibi's panel is John Kenneth Snelson, and Mr. Snelson is no stranger to the Board. 125 Mr. Snelson holds an engineering degree from Cambridge University. He is a professional engineer in Ontario. He has many years of experience in electrical-utility matters and that is outlined in his CV, which is included at tab 2-A of I guess what would now be Exhibit 1.2, Abitibi's February 28th evidence. 126 Mr. Snelson spent 24 years in power-system planning with Ontario Hydro, and for the past ten years he has been an independent consultant with Snelson International Energy dealing with electricity rates and restructuring. Mr. Snelson has served on the OEB's transmission-system-code task group. He has appeared as a witness in many proceedings before the Board, including the Hydro One transmission-rates proceeding in which the Board made its decision on net versus gross billing for embedded generation. He has sat on the OEB working group on unbundling of distribution rates and he was a witness in 2002 on behalf of AMPCO -- excuse me, I think that is 2001 on behalf of AMPCO -- in Hydro One's distribution-rate proceeding. 127 I would ask that the Board permit Mr. Snelson to provide opinion evidence as an expert in this matter. I would be happy to elaborate on the reasons for that. I think I have already covered those in taking you through his CV, though, sir. 128 MR. BETTS: Is there any questions or submissions from parties regarding the request for expert status of Mr. Snelson? 129 MS. ALDRED: No, thank you. 130 MR. BETTS: And the Board, in fact, will recognize Mr. Snelson's expertise in this matter. 131 MR. SIDLOFSKY: Thank you, sir. 132 MR. BETTS: We'll swear in the witnesses now. 133 ABITIBI-CONSOLIDATED - PANEL 1; GARTSHORE, SNELSON 134 J.GARTSHORE; Sworn. 135 K.SNELSON; Sworn. 136 MR. BETTS: Thank you. Please continue, Mr. Sidlofsky. 137 MR. SIDLOFSKY: Thank you, sir. As I said, sir, I expect to be about 20 minutes to begin. 138 MR. BETTS: Thank you. 139 MR. SIDLOFSKY: Thank you. 140 OPENING SUBMISSIONS BY MR. SIDLOFSKY: 141 MR. SIDLOFSKY: Sir, we are here this morning on a proceeding that began with a submission to the Board in April 2002 by Abitibi-Consolidated Company of Canada with respect to the manner in which the Board-approved transmission-rate schedules are being applied to Abitibi by Hydro One Networks Inc. On the basis of that submission, the Board determined in October 2002 to issue a notice of its intention to issue a compliance order against Hydro One under section 75 of the Ontario Energy Board Act 1998. 142 This hearing is being held at the request of Hydro One in response to the Board's notice. 143 Abitibi employs over 2,700 people at five plants across Ontario. It is Abitibi's Fort Frances complex, an industrial complex of mills at which over 750 employees produce groundwood specialty papers and market pulp, that is the subject of today's proceeding. 144 The evidence of Abitibi and that of Hydro One is already on the record. There has been a bit of an exchange of letters in the past week or so with some additional material that may be referred to on cross-examination, and I expect that that will be introduced as we proceed. 145 Abitibi's witnesses will be touching on the key points of their witness statements. They have already adopted the Abitibi April 30th, 2002, submission to the Board, and Abitibi doesn't believe that there is any need to take up the Board's time repeating that simply for the transcript. Abitibi's evidence is there. 146 Now, Abitibi's witness panel has been sworn, but I would like to do a few things initially. First, I would like to give the Board an introduction to the Abitibi Fort Frances complex. I would like to explain the issues that are raised in this proceeding, and I would like to explain why Abitibi is before the Board today. 147 First, an introduction to the Abitibi complex. Now, in front of you are large versions of two items that have already been filed with the Board, and we have provided the blow-ups for you to assist you in understanding Abitibi's circumstances. Jim Gartshore will take you through them in more detail, but I would like to point out a couple of features of each. The first item, that will be on the Board's right, is an air photo originally provided at tab 2-B of Exhibit 1.1, the original Abitibi submission. 148 The area in pink on that air photo represents the Abitibi Fort Frances complex. Abitibi's electricity demand at that complex, as you will hear, is approximately 75 megawatts. 149 The green area located in the middle of the complex is a co-generation plant owned by Westcoast Power. Abitibi operates that plant and is the registered market participant for that facility with the independent electricity market operator. Abitibi's generator licence includes the Westcoast plant. 150 Abitibi has the right to purchase that plant now at a fixed price and for a dollar in 2008. There is a power purchase agreement between ICG Utilities, Westcoast's predecessor, and Ontario Hydro, now administered by the Ontario Electricity Financial Corporation, and that agreement provides that the output from the Westcoast plant is sold to Ontario Hydro. It is now being sold into the IMO-administered wholesale electricity market. 151 It also provides that to the extent the plant is delivering power, it is to first deliver power to Abitibi, and that makes sense in this context because the only way for the power to move out of that plant is through Abitibi's internal electrical system. 152 Abitibi also owns approximately 16 megawatts of hydraulic generation in the complex, so that in total, there is approximately 116 megawatts of generation capacity in the complex. 153 The red lines on the air photo represent Abitibi's internal electrical system, and that system moves electricity around the complex at a transmission voltage. Abitibi is not a licenced transmitter, and as you'll hear from Mr. Snelson, regulations under the Ontario Energy Board Act exempt transmitters such as Abitibi from licencing requirements and from the requirement to obtain a rate order from the OEB. 154 The light blue line in the upper right-hand corner of the air photo is what you will hear referred to today as the F2B line. That's a line owned by Hydro One that runs between the substation owned by Abitibi, marked as item B on the photo, that is the red rectangle immediately abutting the yellow line there, and a transformer station that is off the air photo, but a transformer station owned by Hydro One at 8th Street in Fort Frances at the other end of the F2B line. 155 The Hydro One transformer station is just under a kilometre away from the Abitibi substation, and as you'll see in the simplified single-line drawing, which I'll get to in just a moment, the Hydro One transformer station is where the revenue meter that measures the power flow from the regulated transmission system is located. 156 Finally, the yellow line on the air photo has historically been the delivery point between Abitibi and Hydro One in agreements between those parties. 157 It is referred to as the delivery point in the 1989 power purchase agreement between ICG and Ontario Hydro. It is also referred to as the delivery point in the 1997 agreement between Hydro One and Abitibi for power. 158 The second item to the Board's left is a simplified single line diagram of Abitibi's internal electrical system. In the normal course of Abitibi's operations, the Westcoast plant and the hydraulic generation provide all of the power for the complex. Any electricity that is not consumed by Abitibi flows out of the complex, along Hydro One's F2B line and to the 8th Street transformer station. 159 The revenue meter that measures that flow, as I mentioned, the flow to or from Hydro One's regulated transmission system, is located at the Hydro One TS on 8th Street. 160 Once again, in the normal course of Abitibi's operations, as you'll hear from Mr. Gartshore and Mr. Snelson, all of the electricity used in the Abitibi complex is produced in that complex. Abitibi doesn't take power from the regulated transmission system. 161 On occasion, the evidence will show that the Westcoast plant will not be operating and that when that happens, Abitibi will withdraw power from the regulated transmission system through the F2B line. 162 Now, the issues before you in this proceeding can be summed up in a few words. 163 First, is net versus gross load billing for embedded generation; and second, is contribution by a transmission customer to the building of the line connection assets that it uses. 164 Now I would like to take a few minutes to explain those. First, the distinction between net and gross load billing. The Board provided an explanation in its May 2000 decision on Hydro One's application for transmission rates to come into effect on market opening. I'll be referring to that decision as the transmission decision, and the Board has copies of that decision in both the Abitibi submission and the Hydro One witness statement. 165 That was the Board's file number RP-1999-0044. At paragraph 3.2.3 of the Board's decision, the Board explained that under net load billing, the charges for a transmission customer are calculated on the basis of a charge determinant that is measured on the meter or meters reading a load the customer draws from the regulated transmission system. 166 Using the simplified Abitibi line drawing as an example, the charges would be calculated based on the reading of the meter at the Hydro One 8th Street TS. In most months of the year, the electricity is flowing out of the Abitibi complex into the regulated transmission system because more power was produced in the complex than is used in the complex. 167 That would mean that in one of those months, Abitibi would not be subject to transmission charges. Of course, Hydro One will tell you that it is not quite that simple, and that is why we are here. 168 At paragraph 3.2.4, the Board explained that under gross load billing, the charges for a transmission customer are calculated as under net load billing, plus the charge determinant for the load supplied by any embedded generation. What that means, using the Abitibi complex and the simplified drawing as an example, but leaving aside the hydraulic generation, is that if the Westcoast plant puts out 100 megawatts and Abitibi's demand totals 75 megawatts, Abitibi will be billed on the basis of the 75 megawatts of demand, even though none of the electricity used came from the regulated transmission system. 169 The transmission decision was the result of the Board's hearing on the rates designed by Hydro One to recover the $1.182 billion year 2000 revenue requirement for its transmission system. 170 The Board gave a great deal of consideration to how transmission customers should be charged for transmission service during the hearing. Transmission charges are allocated among three pools: Network, transformation and line connection. The Board defined these at paragraphs 2.1.3 through 2.1.5 of the transmission decision. 171 Now, only network and line connection charges are relevant to today's proceeding. According to the Board, the transmission network system is the backbone of the transmission system that is used by all transmission customers, and includes all of the 500 kV, 230 kV and 115 kV circuits that are normally operated in parallel with the 500 kV circuits. 172 The network pool also contains the 345 kV, 230 kV and 115 kV connections with neighbouring jurisdictions and all transformation and switching stations performing a network function. 173 The line connection pool consists of the radio parts of the transmission system that emanate from the network facilities and connect customers to the transmission network. 174 The Board concluded that network charges would be based on net load billing. Line and transformation connection charges would be based on net load billing in the case of existing embedded generation; that is, generation for which all approves have been obtained prior to 1998, when the Energy Competition Act came into force, and gross load billing for line and transformation connection charges for new embedded generation. 175 Am I going a little too fast for the Board as well or just the -- 176 MR. BETTS: No, I think it is just the court reporter, but understandably, the record has to be clear. 177 MR. SIDLOFSKY: Absolutely. 178 MR. BETTS: Typically, when all of us read, you tend to read a little quicker than you speak, so please proceed. 179 MR. SIDLOFSKY: Whether the embedded generation is existing or new, network charges are to be billed on a net basis. 180 One of the Board's findings in opting for net load billing over gross load billing at paragraph 3.2.27 of the transmission decision was that gross load billing for network services would necessitate highly complex rules and regulations that would have nothing to do with the level of transmission services taken or the cost of providing transmission service. 181 Among other things, these rules would place some industrial customers on whom gross load billing would be imposed at an unfair disadvantage compared to their competitors who, by historical circumstance, enjoy net load billing. 182 In opting for net load billing, the Board said that, "on balance, the Board finds that net load billing shall apply to network transmission service. Current users of the transmission system will continue to pay for the level of transmission service they use." 183 In the Board's view, given the circumstances presented, net load billing for network service is a fair, more practical and simpler system to apply. It removes the arbitrariness inherent in gross load billing. It removes the uncertainty over future transmission pricing for embedded generation, and it does not frustrate the objectives inherent in open access, particularly the opening up of the energy market to alternative generation. 184 The Board recognized that there would be some cost impacts as a result of its findings, but the Board went on to say that they ought to be mitigated by anticipated developments in new generation. 185 As you can see, sir, embedded generation is a key to net load billing. The Board said in its transmission decision that "generation that is not connected directly to the transmission system and is located behind the meter that registers the electricity supplied from the regulated transmission facilities is referred to as 'embedded generation'". 186 One schedule of Hydro One's pre-filed evidence in its transmission rate application addressed net load billing versus gross load billing. Hydro One noted that the generation that is not connected to the transmission system is defined as embedded generation. Hydro One went on to state that for the purpose of that schedule, that is, for the purpose of its evidence on net load billing, in the application to set rates to recover the revenue requirements for its transmission system, that the term refers to generation that is located behind the meter that registers the electricity supplied from the regulated transmission facilities. 187 The behind-the-meter definition of embedded generation was used in other Hydro One evidence in its transmission rate hearing and I am aware that Mr. Moran or Mr. Thiessen provided copies of that material by fax to the parties in the past few days. 188 As you can see from the simplified drawing, and as Abitibi's evidence shows, the Westcoast facility is behind the meter that registers the electricity supplied from the regulated transmission facilities. It is not connected to Hydro One's regulated transmission system. That is consistent with Hydro One's definition in its evidence in its transmission-rate application to recover its revenue requirement for its transmission system. 189 Now, why is Abitibi before the Board? Abitibi's position in this matter is that all of the generation in the complex, both the hydraulic generation and the Westcoast facility, is behind the meter that registers the electricity supplied from the regulated transmission facilities and it's existing embedded generation, having been operating and selling electricity to Ontario Hydro for over a decade. Mr. Gartshore will indicate that that plant went into operation in 1991. Under net load billing, Abitibi should be paying for network charges based on its demand from the regulated transmission system, net of the electricity supplied by all of the generators in its complex. 190 Now, there is an additional issue with respect to line-connection charges. Paragraph 3.4.2 of the Board's transmission decision state that "if a customer has fully contributed to building of a transformation station or to building of their line connection to the network station, the costs associated with those assets are not assigned to the respective connection pools, and the customer will not pay charges related to those services." 191 Abitibi's submission includes evidence on the contribution made by Boise Canada, which was Abitibi's corporate predecessor, to the building of Hydro One's F2B line that connects Abitibi to Hydro One's network station at 8th Street. Mr. Gartshore will also comment on this matter. 192 If the Board accepts Abitibi's evidence in this regard, then Abitibi will not be liable for connection charges in any event. If it does not accept Abitibi's evidence in this regard, then Abitibi would be liable at most for line connection charges on a net basis. 193 Abitibi is here today because Hydro One is insisting on charging Abitibi on a gross load basis for network and line connection service with the exception that Hydro One is netting out the approximately 10 megawatts of generation capacity available from the hydraulic generators owned by Abitibi. That means that even in a month in which all of Abitibi's electricity requirements were being supplied by the generators in the Abitibi complex, Abitibi would be billed as if almost all of its demand, with the exception of the hydraulic output, was being withdrawn from the regulated transmission system. If Abitibi's peak demand in the month was 75 megawatts, it would be billed on the basis of 65 megawatts having come from the regulated Hydro One transmission system, even though it did not obtain that electricity from the regulated transmission system. 194 Abitibi is before the Board because Hydro One's approach is not consistent with the Board's transmission decision. It is not consistent with the way in which other transmission customers are treated, even transmission customers that were historically billed on a gross basis, and I'll speak to the way in which Abitibi was historically billed in a moment. 195 Hydro One's insistence on gross load billing for Abitibi is an example of exactly the kinds of rules and regulations that have nothing to do with the level of transmission services taken or the cost of providing transmission service, and that the Board rejected in opting for net-load billing. 196 Abitibi has been trying to resolve the matter of its transmission charges since the fall of 2000. Three months before the Board issued its initial rate order for Hydro One's transmission rates and a year and a half before the Board issued the final transmission rate schedule that allocated transmission charges among Hydro One, Canadian Niagara Power, Great Lakes Power and Five Nations Energy. 197 Until market opening, Abitibi was paying a bundled price for power, and that included a component attributable to transmission. The Board described the bundled cost of power this way, in the transmission decision at paragraph 1.3.3: 198 "The rates charged to the various rate classes were for bundled service comprising power generation/supply, delivery of power by the high voltage transmission grid to direct industrial customers and local distribution companies, as well as distribution of low-voltage electricity to over 1 million rural customers." 199 Abitibi was paying that bundled price because it doesn't own the power produced by the Westcoast plant. Even though the power being used by Abitibi was the power produced by the Westcoast plant, the power was contracted to Ontario Hydro so that Abitibi had to make different financial arrangements to pay for it. This meant from the time the plant became operational in 1991, Abitibi was paying Ontario Hydro, and then Ontario Power Generation, a price that included the costs of operating and maintaining a system through which Abitibi did not normally obtain its power. This situation was similar to that of municipal electric utilities that were Ontario Hydro customers and are now Hydro One transmission customers and had non-utility generators like Westcoast connected to their systems. 200 Like Westcoast, Ontario Hydro would pay the embedded NUG a price set out in its power purchase agreement and despite the fact that the NUG was injecting its electricity into the MEU or now LDC system, Ontario Hydro would charge the MEU based on total electricity consumption including the electricity received from the non-utility generator. 201 Market opening should have meant, among other things, the unbundling of transmission charges from commodity prices. For Abitibi, it would mean that while it couldn't avoid buying its commodity from the wholesale market or through other contractual arrangements, because west coast's power was contracted to Ontario Hydro and then OEFC, it would not be paying for transmission service that it didn't use because of unbundling in the new market. 202 That is exactly what market opening meant for the MEUs. They began to pay for transmission on a net basis regardless of whether the generators embedded in their systems were selling electricity directly to the MEUs or into the wholesale electricity market. Other transmission customers that had embedded generation, even at transmission voltages, continued to get the benefit of net billing. One customer that no longer owns the generation to which it is connected continues to receive net billing as it did when it owned that generation. Abitibi, in contrast, is still being charged on a gross basis. 203 Now, what relief is Abitibi seeking from the Board? Abitibi is before the Board seeking the following relief. 204 With respect to the applicability of network transmission charges, Abitibi requests that the OEB confirm that Abitibi will be billed for network transmission charges on a net load basis, and more particularly, net of energy received from both the hydraulic generation facility that it owns and the Westcoast facility; and that the OEB direct Hydro One to take all steps necessary to ensure that the IMO billing and settlement process reflects net load billing for network services for Abitibi. 205 With respect to the applicability of line connection charges to the complex, Abitibi requests that the OEB confirm that the Hydro One line connection assets used by Abitibi are not subject to line connection charges and that the OEB direct Hydro One to take all necessary steps to ensure that no line connection charges are levied against Abitibi or collected by the independent electricity market operator. 206 And in the alternative, that the OEB confirm that Abitibi will be billed for line connection charges on a net load basis. More particularly again, net of energy received from both the hydraulic generation facility and the Westcoast facility. 207 With respect to both network and line connection charges, Abitibi requests that the Board order Hydro One to reimburse Abitibi, with interest, the difference between the total payments which may have been made by Abitibi on account of transmission on the basis of gross billing for network and line connection services since the opening of the wholesale electricity market in May of last year, and the amounts of those payments calculated on the basis of the OEB's decision in this application. That the Board, if necessary, impose these directions as conditions of Hydro One's transmitter licence, and if necessary, amend the relevant transmission rate schedule, and finally, that the Board order Hydro One to pay all of Abitibi's costs related to this application. 208 To conclude, sir, Abitibi is an industrial customer served by approximately 100 megawatts of existing embedded generation. Ownership of the commodity is irrelevant. For over ten years, Abitibi paid a bundled cost of power on a gross basis that included transmission services when it normally did not take electricity from the regulated transmission system. 209 Market opening created an opportunity to correct this historical inequity, and Hydro One, while allowing net billing for some of its customers that historically paid for their power on a bundled basis, including transmission on a gross basis, has denied that equitable treatment to Abitibi. 210 So those are my comments. I would like to take the Board into the evidence of Mr. Gartshore and Mr. Snelson. 211 MR. BETTS: Please proceed. 212 MR. SIDLOFSKY: Thank you. 213 MR. BETTS: Actually, as I look at the clock, I wonder if this would be an appropriate time to take a bit of a break for everybody, and you can return then, Mr. Sidlofsky, and begin the examination of your witnesses. 214 Let us break now until 11 o'clock, and we will resume at that time. 215 We stand adjourned. 216 --- Recess taken 10:40 a.m. 217 --- On resuming at 11:00 a.m. 218 MR. BETTS: Okay, Mr. Sidlofsky, before we -- 219 MR. SIDLOFSKY: I switched seats. 220 MR. BETTS: Yes. 221 MR. SIDLOFSKY: I am trying to keep Mr. Moran happy, sir. 222 MR. BETTS: I'll look for you every time we come in. 223 MR. SIDLOFSKY: I'll be at the back. 224 MR. MORAN: Now that Mr. Sidlofsky has finished his evidence, he decided to move to the counsel table. 225 MR. SIDLOFSKY: I'll file my CV next time too, sir. 226 MR. BETTS: Yes. Are there any preliminary matters before we begin? 227 Then, Mr. Sidlofsky, please continue. 228 MR. SIDLOFSKY: Thank you, sir. 229 MR. BETTS: And just for your information, we'll keep going for probably about an hour and a half and break for lunch at roughly 12:30, or when we find an appropriate break in that time range. 230 Sorry, Mr. Sidlofsky, please continue. 231 MR. SIDLOFSKY: That's okay, sir. 232 EXAMINATION BY MR. SIDLOFSKY: 233 MR. SIDLOFSKY: Just to bring us back after the break, I note that the evidence that you will hear from Mr. Gartshore and Mr. Snelson follows a number of themes. 234 First, that the Westcoast facility is fully integrated into the Abitibi complex and is behind the meter that registers the electricity supplied from the regulated transmission facilities; the Westcoast facility constitutes existing embedded generation; and Abitibi has fully contributed to the cost of building the F2B line. 235 Sir, Mr. Gartshore will be presenting evidence on the mechanics of the Abitibi complex, issues related to the manner in which electricity is conveyed around that complex, and he'll also be discussing Abitibi's position on the delivery of electricity to the site, and finally, the contribution by Abitibi to the building of the F2B line. 236 So I'll begin with Mr. Gartshore. Sir, you have already been qualified and I have gone through your qualifications. Could you perhaps move to a description of the Abitibi-Consolidated complex and the co-gen facility. 237 And sorry, Mr. Chair, it is not really a preliminary matter, but Mr. Gartshore intends to stand up and point out a few things to you. I have spoken to the reporter on this, and she tells me that shouldn't be a problem. Mr. Gartshore will certainly speak as clearly as he can and as loudly as he can to make sure we are on the transcript. 238 MR. BETTS: If there is any difficulty, it will probably be for people further back in the room. But if Mr. Gartshore can project his voice as well as possible, I am sure that will be fine. 239 MR. SIDLOFSKY: That's why I resisted Mr. Moran's attempt to move me back there. This is as far as he gets me, sir. 240 Okay, Mr. Gartshore, could you take us through the plant? 241 MR. GARTSHORE: Sure. We'll start with the complex. The complex produces about a thousand tons a day of pulp and paper. It was originally built in 1914. It has been modernized over the years and improved. It consists of a large number of buildings, and we'll point some of those out in a minute. The co-gen facility located inside the complex uses steam and natural gas as the prime movers to turn the turbines. Abitibi has the right to purchase that co-gen plant now, we're in the buy-out period now, it started last year, but we can purchase it for a dollar in 2008 and we can purchase it for more money sooner, we are into that buy-out period right now. 242 Abitibi Consolidated is a generator, licenced as a generator on that site, and we produce over 100 megawatts of power on that site. 243 I just wanted to say that the co-gen facility is completely integrated into the mill. The site is producing electricity, it produces steam and the mill relies wholly on the steam to operate the rest of the processes, and we also operate the co-gen plant and maintain the co-gen plant. That was the way the original mill was set up, and it is a good way because it incents us to run the plant efficiently because we can't survive without the electricity or the steam. 244 In addition to the co-gen plant, we also produce 10 megawatts of power, hydraulic power, at the existing dam site. 245 MR. BETTS: I think we are waiting for somebody. Mr. Sidlofsky? 246 MR. GARTSHORE: Can I get up and just point some things out? 247 MR. BETTS: Yes, please. 248 MR. GARTSHORE: It is easier to get up and point them out than to sit down. 249 First, this is an overhead aerial photo of the complex and the town, and the pink is what we are calling the complex. It is the mill. That's where the pulp mills are, the paper mill and the generation is. 250 It is quite big, this is the town beside it, so these are city blocks, so it is a large number of city blocks, plus there is some of it that is not on the map that extends down here and it extends up in this area. 251 So if we start at the beginning, the light blue is the F2B line, that's the line connection to the Hydro One system and that is the line that is in dispute. We think we have contributed wholly to the building of that line. 252 The yellow is the delivery point to the complex. The red is the internal 115 kV system, and we move power through the complex on that 115 kV system. 253 The green is the co-gen plant. And some of these buildings, this is a pulp mill, a Kraft pulp mill, GroundWood Mill and the paper mill over here. 254 So if we move to the one line, which is easier to see, again, this is the F2B line, so that is the line -- 255 MR. BETTS: If you could speak as loudly as possible. I think if you come to this side, perhaps we can certainly hear you and maybe they can as well. 256 MR. GARTSHORE: Sure. This is the F2B line, which is the blue line in that diagram. It runs from the complex about a kilometre, a little less than a kilometre up to the Hydro One substation, and that's where our revenue meter is. 257 The red is the internal 115 kV transmission system at the complex. There are six large transformers, two at the co-gen site, three here between the GroundWood Mill and Kraft Mill, and one at the paper mill. 258 The internal generation is shown right here, that is eight 2-megawatt units, 16 megawatts installed, roughly 10 megawatts on average. 259 All the power for the mill is provided from the co-gen plant which produces around 100 megawatts of power, a 58-megawatt gas turbine and 58-megawatt steam turbine. 260 MR. SIDLOFSKY: Sorry, was that 58 gas, 42 steam? 261 MR. GARTSHORE: Yes, I'm sorry, I had that backwards. 58 gas turbine and 42 steam turbine, so together, it is 100 megawatts. The load in this area is 60 megawatts and over here it is about 15, because it is offset by the 10 that is generated. So on a normal day, and for the last -- certainly since 1991, 100 megawatts of power comes out of here -- 262 MR. BETTS: As much as possible, since the record won't show where you are pointing, try to refer to the sections that they are coming from and going to. 263 MR. GARTSHORE: Sure, there is 100 megawatts of power generated at the Westcoast co-gen facility. All of the power from the mill is supplied from the Westcoast facility, which is 75 megawatts, it gets consumed in the mill. And in a normal day, there is a power flow of 25 megawatts coming out of the complex going to the Hydro One substation. 264 So the way it was set up, there is meters installed at the co-gen plant, which measures the output at the co-gen plant. There is our old revenue meter at the 8th Street Hydro One station and there is subtraction that takes place, so what is generated at the co-gen plant is metered; what shows up at 8th Street is metered. The difference is what is consumed by the mill, and on a normal day that is 75 to 100 megawatts. 265 MR. BETTS: Thank you. 266 MR. SIDLOFSKY: Sir, sorry, what happens when the mill is -- when the co-gen facility is not operating? 267 MR. GARTSHORE: When the co-gen facility is out of operation, we would be taking power from Hydro One, and that can happen three to four times a year on a scheduled maintenance, when we do the maintenance on the plant; or on a breakdown, or on a statutory holiday. 268 So three to four times a year, we would be taking power from the Hydro One system. In fact, we can operate the worst of the Hydro One system and have on a number of occasions as a result of outages or a lightening storm, the complex can separate and run completely on its own, in which case we would be getting billed on a gross basis even though we are not even connected to the Hydro One system. 269 MR. SMITH: You say three or four times a year; is this for a matter of hours or days? 270 MR. GARTSHORE: It, typically, once a year we'll take the co-gen plant down for major maintenance. That could be two weeks, two to three weeks, even up to a month depending on how much maintenance had to be done. And on other occasions, it would only be for a matter of a few hours, but we would still probably hit a peak after those few hours and have to be charges for the month. So I would say three to four months a year we would be looking at paying network and land connection charges. 271 So I want to talk a little bit about the development of the co-gen plant. It dates back to discussions in the '80s, late '80s. I was involved with them. It was about the supply of power to northwestern Ontario. There was an anticipated shortfall. So the result of those discussions between Boise Cascade, which was our predecessor company, Ontario Hydro at the time, and Westcoast, was he development of the co-gen plant and it was originally intend that had all the power can be used at the mill, because that is the only place it can be used. The load is right beside the generator. The power gets consumed and the excess would go out on to the Ontario Hydro grid at that time. 272 Just one more thing about the steam. It is very important to understand that the co-gen plant is heavily integrated into the mill. The mill cannot survive without the steam. The building of the co-gen plant enabled the company at that time to shut down an old steam plant. We were making our own steam at the time, and the new co-gen plants provided reliable steam -- lots of steam, which is a big benefit of the co-generation plant, to get the steam and electricity. 273 MR. SIDLOFSKY: Sir, is Westcoast obligated to supply Abitibi-Consolidated? 274 MR. GARTSHORE: Yes, the 1989 power agreement stipulates that the power generated at the co-gen plant will be used by the mill as it is generated, because that is the only way it can go, it has no other way to get out of the mill. So the power is delivered to the mill loads, it is used at the mill loads, and the excess goes out on to the Hydro One system. 275 The delivery points are the same, they are the yellow on the aerial photo. So the delivery point for power from the co-gen plant and the delivery point for power to the mill when it takes power is that yellow delivery point. 276 MR. SIDLOFSKY: Sir, if I could take you to the Abitibi submission, tab 2, schedule D of Exhibit 1.1, which is the April 30th, 2002, submission. 277 MR. BETTS: That was tab D, as in Donald? 278 MR. SIDLOFSKY: D as in Donald, sir, yes. 279 And sir, if I could take you to page 8 of that agreement, do you have that there, Mr. Gartshore? 280 MR. GARTSHORE: Yes, I do. 281 MR. SIDLOFSKY: Okay, could I just have you read section 5.1, please. 282 MR. GARTSHORE: Okay, 5.1 on page 8: "To the extent that ICG Ontario is delivering capacity power, ICG Ontario shall deliver capacity power directly to Boise Cascade from time to time on behalf of Hydro and delivery the balance on behalf of Hydro at the delivery point." 283 MR. SIDLOFSKY: Just to make sure we are on the same page, that is Boise Canada in the agreement, is it not? 284 MR. GARTSHORE: Boise Canada, I'm sorry. 285 "The quantity of such capacity power delivered to Boise Canada shall be the amount of capacity power measured at the metering point minus the amount of capacity power measured at the delivery point. Such power delivered to Boise Canada shall be deemed to be delivered at the delivery point provided that such capacity power is received by Boise Canada. ICG shall guarantee that all capacity power measured at the metering point shall be delivered or deemed to be delivered to Ontario Hydro at the delivery point." 286 MR. SIDLOFSKY: And sir, the delivery point is also defined in that agreement; correct? 287 MR. GARTSHORE: Yes, it is. 288 MR. SIDLOFSKY: And I think if I could take you to page 3, section 1.1 of that agreement -- excuse me, 1.11 of the agreement. It is actually page 5 of the agreement, sorry. There is a definition of "delivery point" just down from the middle of the page. Could I have you just read that definition, sir? 289 MR. GARTSHORE: Sure. "Delivery point" -- 290 MR. SIDLOFSKY: Sir, does the Board have that agreement? 291 MR. BETTS: Yes, we do, thanks. 292 MR. SIDLOFSKY: Thank you. 293 MR. GARTSHORE: "Delivery point for the supply of power from ICG Ontario to Ontario Hydro is the same point that is selected for the supply of power from Ontario Hydro to ICG and from Ontario Hydro to Boise Canada, and shall be Ontario Hydro's line dead-ending insulators installed on Boise Canada's plant located at the substation on the corner of 3rd Street West and Central Avenue in the town of Fort Frances, Ontario." 294 MR. SIDLOFSKY: Just so we are clear, that is the yellow line you have shown in the air photo; is that right? 295 MR. GARTSHORE: Yeah, that is the yellow line, the corner of Central and 3rd. 296 MR. SIDLOFSKY: And has that historically been your delivery point for power? 297 MR. GARTSHORE: Yes, it has. 298 MR. SIDLOFSKY: So that point is the same as the deemed delivery point for the co-gen facility? 299 MR. GARTSHORE: Yes, it is. 300 MR. SIDLOFSKY: And you have already indicated that there is no direct connection between the co-gen facility and the Hydro One assets; is that right? 301 MR. GARTSHORE: No, there is no direct connection. The co-gen plant is directed to Abitibi's internal 115 kV transmission system. 302 MR. SIDLOFSKY: Sir, are you aware that Westcoast is a transmission customer of Hydro One? 303 MR. GARTSHORE: Westcoast, no, no, they are not. 304 MR. SIDLOFSKY: Sir, I think you have included with your witness statement, which would be Exhibit 1.2, a copy of a letter from Westcoast to Hydro One to that effect; is that right? 305 MR. GARTSHORE: Yes, I have. That was a letter that was sent to Westcoast by Hydro One -- or actually, back up. Hydro One sent a letter to Westcoast about being a transmission customer, and Westcoast responded saying they were not and did not need to be because Abitibi was the registered market participant for them. 306 MR. SIDLOFSKY: And, sir, on what basis is Abitibi currently being charged for transmission? 307 MR. GARTSHORE: Abitibi is being charged on a gross basis for both network and line connection charges. 308 MR. SIDLOFSKY: And have you ever operated without any connection to the Hydro One transmission system? 309 MR. GARTSHORE: Yeah, as I said earlier, we have. There have been occasions when the F2B breaker has been open and we have been totally isolated from the Hydro One system and have run on our own hydro generation from the co-gen plant and from the hydro plant. 310 MR. SIDLOFSKY: And I think you have said that hasn't changed your history of being billed on a gross basis; is that right? 311 MR. GARTSHORE: No, we would still be billed on a gross basis for both network and line in that situation. 312 MR. SIDLOFSKY: And, sir, have you considered how you should be charged for a transmission? 313 MR. GARTSHORE: Yes, I have. To start with, the transformation is immaterial because we own the six transformers that reduce the voltage for our loads. On the network side, I feel we should only be charged for network when we are taking power from the network. It is true we are connected to the network, but we are not always withdrawing power from the network. 314 When we do withdraw power from the network, we'll pay, like anyone else, but when we don't withdraw power from the regulated network, we should not have to pay. 315 On a normal situation, we are not withdrawing power from the network. In fact, power is going the other way, up the F2B line back into the Hydro One network. 316 In terms of line connection, there is quite a bit of evidence in here that talks to sort of the history there, but if we go way back, the company started the mill in 1914. There was no Ontario Hydro anywhere near the area, so the company had its own network to provide power to its mill. In the mid '20s, they added some more generation remote from the complex and built their own transmission facilities to get power to the mill. It ran that way until the late '50s, when Ontario Hydro came through the area, which was good for the area, obviously, but at that time, the company had been totally self-sufficient up to that point. 317 That same old single-line wood pole line was in service up until the late '60s, and in 1970, there was an agreement struck to replace that old line with a new line, a new F2B line from the complex back to the hydro substation. 318 The deal was that -- well, first off, the company needed more power, we were expanding the mill at that time and were actually adding the kraft mill which was added in the early '70s, which was another 20 megawatts of load plus a rebuild of one of the paper machines, so we needed more power, the line had to be replaced. 319 So the 1970 agreement was struck, Ontario Hydro would build the line. The company would reimburse Ontario Hydro for the line, pay for the line, and if power was taken through that line before a certain deadline, the company, Abitibi, would get its money back. 320 As it turned out, power was not taken. The project was delayed and it wasn't until about a year and a half past the deadline that power was actually taken, so we have no history of ever being reimbursed for our payment of the line. Granted, it was 30 years ago, it is hard to find anyone who was involved at that time, it's over 30 years ago. I would say we have no record of being reimbursed. The line is there, the power was not taken on time, so I can understand the Board's difficulty with our -- you know, trying to prove one way or the other if we paid for the line back then, we feel we did, but if we find that we don't based on the evidence we have submitted, then we should be charged as any other generator, I guess, and we should only have to pay line connection charges on a net basis like any other pre-1998 generator. 321 MR. SIDLOFSKY: Sir, I am just going to take you through a couple of Hydro One's responses to Abitibi's interrogatories. 322 Hydro One, in its response to Abitibi's interrogatory number 7, speaks of its ownership of all of the line towers, sky wires and conductors of circuit F3M, as well as the conductors of F2B from Fort Frances TS, up to and including the dead end insulators at Abitibi's transformer station. 323 Hydro One also says towers and the conductors of F3M were replaced by Ontario Hydro in 1995. A year or so later, the height of the towers was increased to accommodate new conductors for circuit F2B. 324 Do you have any comments on that statement, sir? 325 MR. GARTSHORE: Okay, well, first off, it is not accurate. What actually happened, that F2B line, actually, it is a twin circuit line, steel tower, twin circuit. The F2B circuit feeds the Abitibi complex, the other side of the tower carries the F3M, and that is a line from Hydro One into Minnesota, because the mill is right on the river. The river actually in that diagram is the boundary between the United States and Canada, Ontario and Minnesota. So the F3M, they are two separate circuits. The complex is fed by the F2B and the F3M is Hydro One's tie to Minnesota. 326 That line was improved in 1995, and in fact, there were two towers that were replaced, made higher and stronger, and those two towers have nothing to do with the F2B, those two towers are after the F2B, in fact. 327 If I can, on this drawing, I am not sure it shows, but actually there is one about here, and then there is one about here. 328 What happens is there is two circuits on these towers, the F2B comes here and dead-ends. The F3M comes here and crosses company property and goes to Minnesota. 329 Those two towers were changed in 1995, but nothing was done to the F2B in 1995, so it is essentially the same line as it was in 1970. 330 MR. SIDLOFSKY: Sir, in its response to Abitibi's interrogatory number 4, Hydro One says that the Hydroelectric Power Corporation of Ontario designed, built and operated its connection to the paper mill to serve its customer and that some 20 years later the co-gen facility was built and the connection to the transmitter, at the time Ontario Hydro, was modified to serve its new customer. 331 Any comments on that response? 332 MR. GARTSHORE: There was nothing done to the F2B line when the co-gen plant went in, so before the F2B line replaced the old company line from the company's other hydraulic generating plants. We feel we paid for that line when it was replaced. 333 I guess one way of looking at it is there is less power flowing over the F2B line than there used to be before the co-gen plant was built, so previous to the co-gen plant, there was approximately 70 megawatts coming down the F2 line into the complex. After the co-gen complex, there was less power, there was 25 megawatts going out. 334 So there was nothing done to the F2B line when the co-gen plant was built, but there was some metering and relaying installed to recognize the fact that power flows had changed on that line, but the actual line itself was untouched. 335 MR. SIDLOFSKY: Sir, Hydro One has suggested that Abitibi-Consolidated has historically paid for transmission on a gross basis without complaint. Why are you disputing your liability now for transmission charges? 336 MR. GARTSHORE: Well, as the Board knows, before deregulation power was bundled, there was no way to separate network and line connection from the bundle, so in fact, we were paying for, obviously, network and line connection charges before. We wouldn't have not known what they were. Since deregulation, we now can see what they are, and I don't think we should have to be paying them coming forward. 337 In fact, as soon as we saw how it was going to work and how the charges would be calculated, we began, you know, writing letters and asking questions and trying to get clarification, and we did that through 2000 and 2001 up until this proceeding. 338 MR. SIDLOFSKY: Sir, if I were to take you to tab 2-G, at the April 2002 Abitibi submission. That appears to be a letter from John Harris of Abitibi-Consolidated to Jim Patterson at Hydro One. 339 MR. GARTSHORE: Yes, it is. That is a letter that John wrote after considerable discussion we had at the complex. We were trying to understand how we would be affected by market opening and we realized we had a number of issues around line connection, embedded generation, existing embedded generators, our existing hydraulic facility, our co-gen facility. 340 So we wrote a letter, basically, and asked for some clarification, largely so we could understand how it would work and so we could begin our budgeting process to understand how this would impact us. We received a letter in response; I believe that is the next tab. 341 MR. SIDLOFSKY: That would be at tab H? 342 MR. GARTSHORE: Tab H. 343 MR. SIDLOFSKY: Now the letter in response, just to clarify something. The letter in response is dated November 2nd of 2000, and that refers to an e-mail and attached letter of October 12th. 344 Sir, can you confirm that despite the November 2nd date on Mr. Harris' letter, that is the letter that was sent in October? 345 MR. GARTSHORE: Yes, it was. 346 MR. SIDLOFSKY: And I see in that, in the Abitibi letter, that you were requesting a response by October 23rd; correct? 347 MR. GARTSHORE: Yes, we were. "Please respond by October 23rd, if at all possible." 348 MR. SIDLOFSKY: And, sir, the response from Hydro One, I take it, was negative? 349 MR. GARTSHORE: It was a negative response, yes. So that generated another letter, which I believe is the next tab, that is a letter to Timo Hakkarainen from myself. 350 MR. SIDLOFSKY: And that letter was dated July 3rd, 2001. 351 MR. GARTSHORE: July 3rd, 2001, yes. 352 MR. SIDLOFSKY: And you received a response to that in November of 2001; is that right? 353 MR. GARTSHORE: Yes, November 2001 from Anthony Horton. 354 MR. SIDLOFSKY: So that would take us to tab J at that point; is that right? 355 MR. GARTSHORE: Yeah, that is in tab J, the letter from Mr. Horton. 356 MR. SIDLOFSKY: Again, the response was negative. 357 MR. GARTSHORE: Negative, but again, getting somewhat different reasons from the Timo letter. But again negative, so -- we actually had some conference calls and some other discussion with Hydro One to try to resolve the issue, but we could not come to a resolution. 358 MR. SIDLOFSKY: Was there anything else in writing to Hydro One that you are familiar with? 359 MR. GARTSHORE: Nothing else in writing, but there were at least two conference calls. 360 MR. SIDLOFSKY: And do you recall a submission in March of 2002 to Hydro One? 361 MR. GARTSHORE: March 2002? 362 MR. SIDLOFSKY: On your transmission rates. 363 MR. GARTSHORE: Is it in the exhibits? 364 MR. SIDLOFSKY: No, that one hasn't been filed, sir. 365 MR. GARTSHORE: No, no, I don't, off the top of my head. 366 MR. SIDLOFSKY: And that would have brought you to the April 30th submission? 367 MR. GARTSHORE: Yes. 368 MR. SIDLOFSKY: To the Board. 369 MR. GARTSHORE: To the Board. We felt it was important to try and get clarification before market opening, which is why we worked hard up to market opening to get the other issues dealt with, with Hydro One. 370 MR. SIDLOFSKY: Sir, you have said that Abitibi is entitled to purchase the co-gen facility now or for nominal consideration in 2008. Will anything change with respect to the configuration of the co-gen facility and Abitibi-Consolidated's use of the regulated transmission system once Abitibi owns the co-gen facility? 371 MR. GARTSHORE: No, it won't. The only thing that will change will be the name of the owner. Abitibi-Consolidated will still operate it and maintain it and own it, at that point, and have to buy all the gas for it, which would be a big bill as well, I am sure, but it will operate and maintain it, use the power and use the steam to run the mill. So nothing really changes other than the name of the owner. 372 MR. SIDLOFSKY: And, sir, what would your response be to the suggestion that Hydro One provides Abitibi with other services such as voltage control that would justify gross load billing? 373 MR. GARTSHORE: Well, I would have to say that auxiliary services are a two-way street. The system in that part of the country is quite weak in northwestern Ontario. The co-gen plant actually provided a great deal of stability to the system in that area. 374 In fact, in the past, with Ontario Hydro under previous power agreements, we were responsible for providing some voltage support in the area, so generators don't pay for transmission services or connections and we are a generator, we shouldn't have to. So again, auxiliary services are a two-way street, and they alone should not justify having to pay network charges. 375 MR. SIDLOFSKY: And, sir, in your witness statement, you refer to administrative instruction number NW-150, the January 1997 operating agreement between Ontario Hydro and Stone Consolidated; is that right? 376 MR. GARTSHORE: Yes, and that required Stone, which was another predecessor company of Abitibi-Consolidated, to provide voltage support. Because of the generation on-site we had the ability to do that, so we were actually providing and still do provide support to the system. 377 MR. SIDLOFSKY: Sir, we filed with the Board actually two copies of the administrative instruction number NW-150 in recent days. There was a clean version or a cleaner version that was filed on Friday, I believe, of last week. I have that for you. I would just like to -- I would just like to take Mr. Gartshore to one particular paragraph of that document. I am not sure if the Board has it particularly handy, but I do have copies for the panel. 378 MR. BETTS: I think the copies would be helpful. 379 MR. SIDLOFSKY: Certainly. 380 MR. BETTS: Should this be referenced as an exhibit, Mr. Moran? 381 MR. MORAN: Yes, Mr. Chair. This would become Exhibit 1.4, a document entitled "Administrative Instruction to Manager, Northwest District, title, 'Operations Agreement between Ontario Hydro and Stone Consolidated Corp., Fort Frances', dated January 31, 1997." 382 EXHIBIT NO. 1.4: DOCUMENT ENTITLED "ADMINISTRATIVE INSTRUCTION TO MANAGER, NORTHWEST DISTRICT, TITLE, 'OPERATIONS AGREEMENT BETWEEN ONTARIO HYDRO AND STONE CONSOLIDATED CORP., FORT FRANCES', DATED JANUARY 31, 1997 383 MR. BETTS: Thank you. 384 MR. GARTSHORE: It is administrative instruction NW-150, and on page 6 of 24, so it says: "Within the generator capability, Stone Consolidated Corp. Co-generation will be expected to provide voltage support due to short-term and normal system conditions in the form of our output at the request of Ontario Hydro control and authority. Normal communications between controlling authorities will keep the other informed of the reason for the VAR requests and the capability of the generators. Under normal operating conditions, Stone-Consolidated Corp. will be operating at approximately 90 per cent power factor lagging. 385 So Stone-Consolidated was required to provide voltage support to Ontario Hydro. Generators do not pay for ancillary services they receive from the system. The Board's transmission decision did not require embedded generators to pay on a gross load basis because of ancillary services and Abitibi should be treated like any other site with embedded generation. 386 MR. SIDLOFSKY: Before I get to my next question, I just want to take you back, sir, I had asked you specifically about a March 2002 submission to Hydro One. If I were to show you a document, maybe you could tell me if you recall that, that document hasn't been filed in this proceeding. 387 MR. GARTSHORE: Okay. 388 MR. SIDLOFSKY: And, sir, we don't propose to file it today. 389 MR. GARTSHORE: It was signed by me, so I should remember it. I'll just take a minute. 390 MR. SIDLOFSKY: Sir, my understanding is that that was a submission on transmission rates and a number of other issues as between Abitibi and Hydro One? 391 MR. MORAN: Sorry, Mr. Chair, it is not clear what document is being referred to. 392 I know that Mr. Sidlofsky said he doesn't intend to enter it, so I am not sure -- 393 MR. SIDLOFSKY: Sir, I would like to give Mr. Gartshore a chance to refresh his memory on it, but it's simply a matter of identifying the letter that went to the Board. 394 MR. GARTSHORE: Yeah, it was a letter of February 28th, 2002, to Mr. Rod Taylor from myself, and it dealt with outstanding issues related to transmission charges and to Hydro One Networks M1S transmission line and Crilley distribution station 395 That is another issue we have with Hydro One. 396 MR. SIDLOFSKY: And, sir, that is not part of this proceeding. 397 MR. GARTSHORE: Not part of this. Okay. 398 So there was a number of issues we had with Hydro One, as I said before, we were trying to get resolved before market opening. So this was another letter asking for consideration and asking for a response, and just to paraphrase we said: 399 "As a satisfactory response has not been forthcoming, we have prepared the accompanying submission for you on these and other outstanding issues, and we request that you review it and we would appreciate the opportunity to meet and discuss these issues by the week of March 18th, at the latest. 400 "If these issues cannot be resolved to Abitibi-Consolidated's satisfaction, we may have little choice but to seek appropriate relief from the Ontario Energy Board." 401 So I was basically putting them on notice that we needed an answer, and we were running out of time. 402 So we didn't get an answer, so we filed our request. 403 MR. SIDLOFSKY: Thank you, sir. 404 Sir, I have one more item to file through Mr. Gartshore and that's a spreadsheet that was prepared, and I think I may have mentioned that in my opening submission. 405 It is a spreadsheet that was prepared to illustrate the difference between net and gross load billing in respect of Abitibi's complex. 406 And you may recall, in my comments on Mr. Lokan's intervention request, I had suggested that the difference is closer to $1.7 million than the $2.8 million that is suggested in the Abitibi submission. 407 Sir, again, that was filed with the Board earlier. I have additional copies. It will probably be easier or it may be easier if -- 408 MR. BETTS: We have that one. 409 MR. SIDLOFSKY: Oh, good, thank you, sir. 410 MR. BETTS: So if we could give that an exhibit number. 411 MR. MORAN: Mr. Chair, that would be Exhibit 1.5, a spreadsheet showing calculations that show the difference between gross load billing and net load billing for the Abitibi complex. 412 MR. BETTS: Thank you. 413 EXHIBIT NO. 1.5: SPREADSHEET SHOWING CALCULATIONS THAT SHOW THE DIFFERENCE BETWEEN GROSS LOAD BILLING AND NET LOAD BILLING FOR THE ABITIBI COMPLEX 414 MR. SIDLOFSKY: Thank you, Mr. Gartshore, could I just have you explain that spreadsheet, please? 415 MR. GARTSHORE: Certainly, it was an attempt to try and calculate what the difference would have been between gross and net for line connection and network charges since market opening. 416 So on the left-hand side, billed on gross, that is the actual, on the right-hand side I calculated on net monthly charges. 417 So we were trying to present a figure to give the Board an idea how much money is involved here and the difference comes out to be approximately $1.7 million. 418 Again, this is an estimate. It is run as if we were being charged on net, but perhaps not taking any actions to reduce our charges on net by shutting parts of the mill down or whatever. 419 So I think it provides a good indication of what the value is. I would think we would want to sit down and do a more detailed calculation if we are successful going ahead to determine a rebate or how much money is owed. 420 But I think it is an accurate depiction of what net versus gross would look like for the Abitibi complex since market opening. 421 MR. SIDLOFSKY: Sir, I would have thought that if no power is flowing from the regulated transmission system, then your network charges would be -- for example, your network charges would be zero. It seems like even in months where you have taken less from the system, I am looking, for example, at November of 2002, you are still showing a network charge of 17,000 even calculated on net. 422 MR. GARTSHORE: Well, I think that depicts some auxiliary loads we have in the plant. For instance, the way we are billed, the bill is fairly complex. We buy power for a lagoon which is not in the complex, it is offsite of the complex, and we buy some power for the Town of Fort Frances, a long-standing agreement that we are required to provide approximately 4 megawatts of power to the Town of Fort Frances, so those are all included in our bill receipt. 423 So like I said, this is a good estimation of what it would look like. It is roughly between a million and a half and $2 million per year is what we are talking about. 424 At first we had said 2.8. 2.8 would be if we never took any power from the regulated system and ran completely on our own. There will be months, as I said, where we do maintenance and have a breakdown where we are required to draw power and will be billed accordingly. 425 MR. SIDLOFSKY: Sir, do you have anything else -- anything to add to your comments before I move on to Mr. Snelson? 426 MR. GARTSHORE: No, I do not. 427 MR. SIDLOFSKY: Mr. Snelson, you have heard Mr. Gartshore's description of the co-gen facility and the Fort Frances complex. Does the co-gen facility at Fort Frances correspond to what you consider to be the characteristics of an embedded facility as they were discussed in the Hydro One transmission hearing? 428 MR. SNELSON: Yes, they do. The Board's decision describes embedded generation at paragraph 3.2.1, and it describes it in these terms. It says: 429 "Generation that is not connected to the transmission system and is located behind the meter that registers the electricity supplied from the regulated transmission facilities is referred to as embedded generation." 430 In my opinion, the Abitibi Fort Frances co-generation facility meets that definition, and that is the purpose of my evidence in its entirety. 431 Before dealing with the specifics of how it meets that definition, I wanted to go over some of the characteristics of the co-generation facility. 432 Physically, this co-generation facility is entirely consistent with the general idea of what is a co-generation facility and, through the transmission rate hearing, it was expected that co-generation facilities would be considered to be embedded generation. 433 Specifically, the co-generation facility is within the paper mill property. It provides steam and electricity to the mill, and it is an integral part, as we have heard from Mr. Gartshore, it is an integral part of the operation of the paper mill. 434 This is the normal circumstances where a co-generation facility would be economic as an embedded generator and it would also be very energy-efficient. 435 There is mutual advantage to locating electricity generation and steam facilities together, and this mutual benefit is in the form of energy savings. 436 The rejected heat from producing electricity can be used to produce steam for the process, and this increases energy efficiency. It also provides an environmental advantage in that in this case we are using natural gas, a relatively clean fuel, and using it at high efficiency. 437 There are many co-generation facilities across the province. There are also opportunities for additional co-generation facilities that are under consideration and, over time, some of these will be pursued. 438 Now, the Board's rate order recognized the energy efficiency and environmental benefits of co-generation. Although the Board did not make low environmental impact a condition of net load billing, it appears from the decision that the Board didn't want to discourage co-generation and other local forms of generation through its decision on net versus gross. 439 We expected -- or I expected that the ruling on embedded generation would be applied consistently to both existing and future co-generation plants where the definition is met. 440 MR. SIDLOFSKY: Sir, are there any unusual characteristics of the co-generation facility at Fort Frances, and if there are, how do they affect if the facility should be considered embedded? 441 MR. SNELSON: There are three unusual characteristics. The first is that it is connected at transmission voltage within the Abitibi electrical system. The second is that the embedded generator is not owned by the load. And the third, that if Abitibi co-generation is recognized as an embedded generator, there will be some loss of transmission revenue to Hydro One. 442 MR. SIDLOFSKY: Sir, perhaps we could deal with each of those characteristics in turn. 443 To begin, should the connection of the co-generation at transmission voltage within the plant disqualify it from being considered an embedded generator? 444 MR. SNELSON: No. The connection of embedded generation at distribution voltage is more usual than at transmission voltage. In this case the over 50 kV connection, which is what classifies transmission voltage, the over 50 kV connection is a matter of either an accident of history or a matter of technical convenience, and it doesn't affect whether the facility is embedded, whether the co-generation facility is embedded within the industrial facility. 445 I would point out that the OEB Act recognizes that the distinction between distribution and transmission is subject to some interpretation, and Section 84 allows the Board to reclassify some over 50 kV facilities as distribution or vice versa. 446 Now, embedded generation that is connected at above 50 kV at transmission voltage is unusual but not unique, and I would refer you to Hydro One's response to Abitibi's interrogatory, 6.A.1, and I will read it to save you having to look it up. They say, and this is their quote, exact words: 447 "There is at least one situation where an industrial customer that owns transmission facilities has generation owned by the same customer connected to the transmission's system at that site. In accordance with the current Ontario transmission rate schedules, the load and generation of that customer are aggregated for the purpose of assessing the transmission charges and that customer is treated as a single transmission customer at that site." 448 In short, that customer is net load billed. 449 So in that particular case, Hydro One doesn't consider connection at transmission voltage to be a barrier to a generation being considered embedded, and clearly, for consistency, they shouldn't consider that to be so at Abitibi. 450 MR. SIDLOFSKY: And sir, should separate ownership of the co-generation disqualify it from being considered an embedded generator? 451 MR. SNELSON: No. That is unusual, for an industrial facility for the embedded generator to have separate ownership to the load, but it is not unique. And I believe that the Board has been provided with the Hydro One responses to interrogatories from Casco in the parallel Casco proceeding, and I want to refer to one of those answers. It doesn't refer to a matter that is specific to Casco, it refers to a general matter -- has that got an exhibit number, by the way? 452 MR. SIDLOFSKY: It doesn't at this point. It was filed with the Board recently. 453 MR. MORAN: Mr. Chair, the interrogatories haven't been given an exhibit number. Maybe the simplest approach would be to just use the interrogatory number as the exhibit number, and that way we wouldn't have to have two numbers every time we referred to an interrogatory, if that is suitable. 454 MR. SNELSON: This is interrogatory 6A, part 3, from the Casco proceeding, and the interrogatory asks, as part 3, if there was any situation where a change of ownership of generations occurred since 1998 such that an embedded generator previously owned by the load customer is now owned by a party other than the load customer. And the response said: 455 "Hydro One Networks is aware of only one such situation. In one of the cases described in the table of Other Situation A, there are certain embedded generators connected at the distribution voltage that have changed ownership since 1998. The load served by these generators continues to be billed for transmission charges on a net load basis." 456 So there is one case -- at least one case where an industrial facility is net load billed despite the embedded generator having different ownership. In this particular case the generation is connected at distribution voltage within the plant. The industrial user owned the generation in 1998, and since then has sold it to a third party. 457 So clearly, in that case, Hydro One does not consider separate ownership to be a barrier to net load billing of embedded industrial generation. 458 Now, if we turn to generation that is embedded in local distribution companies, then separate ownership of the embedded generation is the normal circumstance. Now, most generators embedded in local distribution companies are not owned by local distribution companies, and in fact, there are restraints that prevent local distribution companies in those cases from owning generation. But still, the generation connected to local distribution companies is billed on a net basis or, to be more precise, the local distribution company is billed for its transmission services on a net basis for the power that is withdrawn from the regulated transmission system. 459 MR. SIDLOFSKY: Sir, could I just stop you there. Are you aware of how the local distribution companies were billed prior to unbundling for their electricity? 460 MR. SNELSON: Yes. Prior to unbundling, there were some non-utility generators that were connected to local distribution systems that were contracted to sell power to Ontario Hydro in much the same way that Westcoast contracted to sell power to Ontario Hydro at the Abitibi site. And in those cases, prior to market opening, the LDC would pay the bundled transmission rate for the power delivered directly from the transmission system plus the power delivered into the local distribution system by these non-utility generators connected within the local distribution system. 461 And, therefore, they were paying, effectively, for transmission on a gross load basis because even the delivery from the local generation was being charged a bundle tariff including the distribution charges. 462 Now, since market opening, they have been billed on a net basis, and clearly, that represents a loss of -- a reduction in the load that is paying the transmission rate. If they were billed on a gross basis, then the load would be higher and there would be more revenue for Hydro One. 463 MR. SIDLOFSKY: Sorry, sir, can you find anything in the Board's transmission decision that would deal with the issue of ownership? 464 MR. SNELSON: I can't find any reference in the Board's transmission rate decision that conditions the classification of generation as embedded generation on there being common ownership of the load and the embedded generator. 465 Now, there is also other material in the Board's decision that shows that they clearly expected separate ownership. As I have said, LDCs are not normally allowed to own generation. There is a lot of discussion in the Board's rate order about merchant generation connected to local distribution companies, and by definition, if the LDC can't own those, they have to be separate ownership. 466 And I would point you to the section of the Board's decision that deals with the definition of embedded generation. Now, I have read the section -- this is 3.2.1. I have read the section that generation that is not connected to the transmission system and is located behind the meter that registers the electricity supplied from the regulated transmission facilities is defined as embedded generation. 467 Immediately following that, in the same paragraph, it says: "Similarly, a connection of any existing or new merchant generation to directly supply an LDC or other customer will reduce demand on the transmission system." 468 So the Board is clearly contemplating, in the concept of embedded generation, that merchant generation is included and merchant generation in an LDC must be of different ownership. 469 MR. SIDLOFSKY: Sir, just moving to the loss of transmission revenue, should that disqualify the co-generation plant from being considered an embedded generator? 470 MR. SNELSON: Again, the answer is no. When we are considering net versus gross billing, it was being recognized throughout that net load billing will cause some reduction in the load that pays the transmission tariff. There will be some loss effectively of transmission revenue to Hydro One or to the other transmitters. 471 The purpose of the rate order was to define under what circumstances net load billing would be permitted and that's what the rate order did. 472 Treating most existing co-generation as embedded does not lead to a loss of transmission revenue, and that is because the loads associated with most existing embedded generators in industrial facilities, when net load billed prior to market opening. So they were net load billed under the bundled tariff and recognizing them as embedded generation doesn't cause a loss in transmission revenue. 473 Now, in Abitibi's case, there are these unusual contractual arrangements. Although the energy is actually used locally, notionally it is sold to the Ontario Electricity Financial Corporation under the contract that was previously set up with Ontario Hydro. 474 And because Abitibi doesn't buy that power as a commodity, Abitibi has to buy its commodity electricity from somewhere else and it does that through the IMO market or some other combination of energy contracts. 475 Now, prior to market opening, Abitibi bought its full requirements at the bundled rate from Ontario Hydro, and we have heard that from Mr. Gartshore. They effectively paid for transmission even though no transmission service was being provided. 476 With the bundled rate, there was no means to separate out the transmission cost. You either bought electricity or didn't buy electricity. If you bought electricity, you bought all the components of the electricity service. 477 Now that the market is open, transmission is a separate billing item. It is an unbundled from energy. And it is possible to recognize that the contract path for energy is different to the physical path that electricity actually flows and the physical path of transmission services. 478 Abitibi should be paying transmission based on the physical transmission services because energy contracts have nothing to do with the way in which transmission is priced. 479 There are many energy contracts out in the market, and they can go various ways at the same time. Most of them are not known to the transmitter; some of them are not even known to the IMO. And they are not the basis for transmission services. Transmission services is based on energy that is delivered through meters. 480 I have been through some of the characteristics with respect to generation that is embedded in local distribution companies, and Hydro One, in its answer to Abitibi's interrogatory number 5, has confirmed the essential points; that is, that the existing embedded generation in LDCs with no contracts, that the LDC was billed on a gross basis before the market opening, they are now being billed on a net basis, and that by doing that, there is some reduction in the load that pays the transmission rate, there is some loss in transmission revenue to Hydro One, and that has not been a barrier to those LDCs being billed on a net basis for their embedded generation. 481 Therefore, it seems reasonable that Abitibi -- the fact that recognizing Abitibi as an embedded generation will lose some transmission revenue, it seems reasonable that that should not be a barrier to Abitibi being recognized as an embedded generator. 482 So having looked at these three unusual characteristics, the connection at transmission voltage, the separate ownership and the fact that recognizing Abitibi as an embedded generator will cause some loss of transmission revenue, none of those characteristics should be a barrier to recognizing the Abitibi co-generation plant as an embedded generator, and there are precedents where Hydro One is treating other parties who have those characteristics individually and billing on a net load basis. 483 MR. SIDLOFSKY: And, sir, you have mentioned that separate ownership of embedded generation is unusual. I wonder if you could give us some background as to why that is? 484 MR. SNELSON: Well, I'll deal with this by sort of time period. 485 Before the 1980s, there was no well-developed private generation industry in Ontario. If an industrial company wanted some co-generation within his plant, he would build it himself. In fact, in some cases, as we have heard from Mr. Gartshore, industrial companies even took on the role of the generator and power supplier to local towns in the area because there was no utility in the area. 486 In the 1980s, the independent electricity generation industry started to develop, and Ontario Hydro actively encouraged this through its non-utility generation program. And Ontario Hydro was open to innovative arrangements in terms of how these would be financed and how they would be owned. And Ontario Hydro was open to the idea of having separate ownership of embedded generation. 487 Now, as far as I am aware, the Fort Frances plant is the only co-generation plant that proceeded with separate ownership. 488 In the early 1990s, Ontario Hydro shifted. It decided that it had surplus generation. It dismantled its NUG program. It discouraged all forms of private generation, and if a proposition was made for an embedded generator that would have had separate ownership, then it would have turned that down on the basis that it was not accepting any -- that any embedded generation could have separate ownership. 489 MR. SIDLOFSKY: Sir, do you expect there to be any new proposals for embedded generation with separate ownership, and why is that, if you do? 490 MR. SNELSON: I expect that a significant proportion of the new proposals for embedded generation will have separate ownership, particularly -- my comments relate particularly to the industrial companies. And the reason for this is that many industrial companies who have co-generation potential don't consider themselves to be in the business of generating electricity. They want to invest their capital in their primary business. So it is convenient for them to partner with an electricity-generating company, and that generating company can build and own a generation asset within the industrial facility and sell electricity and steam to the plant. And that is a mutually beneficial arrangement. 491 And in addition, it is possible that some, as we have seen, there is at least one company who has sold his embedded generation plant to a third party. There may be other such circumstances that arise that lead to separate ownership for embedded facilities. 492 MR. SIDLOFSKY: Sir, you heard Mr. Gartshore discuss the location, the historical location of the delivery point for electricity between Ontario Hydro and Abitibi. I'll ask you about that, but I would also like to know what your view is on whether there are different types of transmission in the province. 493 MR. SNELSON: Well, the net effect of the Ontario Energy Board Act and the regulations that the government has brought in under that Act, are to create two classes of transmission. There is licensed transmission, such as Hydro One, Great Lakes Power, and this is transmission that is owned by companies that are in the business of providing electricity-transmission services to the public. 494 There is also non-licenced transmission that is incidental to the main business of the owning company and is not intended to provide transmission services to the public. 495 Now, the IMO, that's the Independent Market Operator, clearly recognizes these two classes, and I will read a small section from the IMO's notice of intervention in the transmission-system-code proceeding, and they say in paragraph 2(e) of their letter under the heading "Operating Requirements and Obligations of Non-licenced Ontario Transmitters": 496 "Ontario regulation 20/02, which was in force on February the 9th, 2002, among other things exempted particular transmitters from certain provisions of the Ontario Energy Board Act 1998, including the need to obtain a transmitter licence. In essence, the regulation has created a new form of transmitter, one that may be exempted from the requirements of a licensed transmitter. Notwithstanding the passage of regulation 20/02, all transmitters (licensed or otherwise) must be required to abide by the operating requirements and meet the obligations of a transmitter, including the minimum conditions that a transmitter must meet in designing, constructing, managing and operating its transmission system." 497 The reason for raising this issue is that there are many documents that refer to transmission; many of them were drafted before February 9th, 2002, when this regulation was brought in, and it is not always clear whether the reference to transmission in those documents should apply to licensed transmission, non-licensed transmission, or both. 498 Now, the practical need for a regulation exempting some transmission from parts of the act arose because of the broad definition of "transmission" in the Act. The definition of transmit in the Act says, with respect to electricity means "to convey electricity at voltages more than 50 kilovolts." 499 Some industrial companies and some generators own over 50 kV facilities, and Abitibi does. They are not in the business to provide electricity-transmission services to the public. The purpose of their over 50 kV facilities is to move around within their own plant, move power around within their own plant. 500 Regulation 20/02 formalized that distinction between licensed and non-licensed transmission facilities, and my understanding is that Abitibi Fort Frances is exempt from regulation 20/02 and that the Abitibi transmission is a non-licensed transmission system. 501 As recommended by the IMO in the transmission-system-code proceeding, it is therefore necessary to carefully interpret how documents should be applied where there are both non-licensed and non-regulated -- or where there are non-licensed transmission facilities, which I may also refer to as non-regulated transmission facilities. 502 MR. SIDLOFSKY: Sir, I am just going to stop you there for a moment. Sir, I have a copy available of Ontario regulation 161-99, that is the Definitions and Exemptions Regulation under the Ontario Energy Board Act. Regulation 20/02 was an amendment to Ontario Regulation 161/99 and exempted certain transmitters from certain sections of the Ontario Energy Board Act. I wonder if this might be a good time to simply provide the Board with copies of that material. 503 MR. BETTS: Yes, please, that would be helpful. 504 MR. SIDLOFSKY: Mr. Thiessen, I also have a few copies for staff, if that would help. 505 Sir, if I might just explain why there are two documents here. The first document is the regulation itself, and in particular, the relevant section is 4.0.2, that is at page 3 of 11 in the printout that I have provided the Board, and what you will see by looking at section 4.0.2 is that clause 57(b) of the Act and the other provisions of the Act listed in subsection 2 of that section of the regulations do not apply to a transmission -- excuse me, to a transmitter under certain circumstances. 506 Subsection 2 at page 4 of the copy that I have provided with the Board -- that I have provided to the Board sets out the other provisions of the Act that are referred to in subsection 1. The second document was prepared for the Board's assistance. It provides copies of the relevant sections that are referred to in section 4.0.2 of the regulation. 507 MR. BETTS: Thank you. 508 MR. SIDLOFSKY: Sorry to interrupt you, Mr. Snelson. 509 Sir, there are two versions of the transmission rate schedule. One is dated January 15th, 2001, and one is dated April 30th, 2002. And the April 30th schedule -- April 30th, 2002, schedule supersedes the earlier one. Could you comment on the differences between the schedules and how those differences would affect the definition of a transmission customer? 510 MR. SNELSON: Yes. The January 15th, 2001, schedule implements the Board's rate order for Hydro One transmission rates, and the rates and terms are specific to Hydro One. 511 The April 30th, 2002 schedule implements the Board's December the 17th, 2001 rate order, which set wholesale pooled transmission rates for all licenced transmitters. 512 To facilitate this change in the rate schedule, language specific to Hydro One had to be generalized to cover other licenced transmitters. 513 And I will consider a couple of examples, and it may help if you just look them up. The January 15th, 2001 transmission rate schedule I believe is schedule F or tab F to the original Abitibi submission, which would be Exhibit 1.1. 514 MR. MORAN: 1.1. 515 MR. BETTS: Thank you, we have that. 516 MR. SNELSON: Okay, and on the first main page of text, section A, Applicability, the first bulleted point describes and in my view defines what is a transmission customer. It says: 517 "The provision of provincial transmission service to the transmission customers which are defined as the entities which own those facilities that are directly connected to the transmission system owned by Hydro One Networks Inc.." 518 So this schedule is very specific, the transmission customer is somebody who owns facilities that are directly connected to Hydro One's transmission system. 519 And with this definition of transmission customer, the co-generation facility at the Abitibi plant is not a transmission customer; it is not directly connected to the transmission system owned by Hydro One. 520 Now, Hydro One relies on the April 30th, 2002 schedule, which supersedes the earlier one, and I believe that that is attached to my witness statement, and in my volume it is at tab H, I don't know if they are all tabbed the same way. 521 MR. SIDLOFSKY: That would be tab 2H, sir, of Exhibit 1.2. 522 MR. BETTS: Thank you, we have that. 523 MR. SNELSON: And the corresponding paragraph, that is, the first bulleted point in section A says: 524 "The provision of provincial transmission service to the transmission customers who are defined as the entities that withdraw electricity from the transmission system in the province of Ontario." 525 And you will notice that we have changed from the transmission facilities owned by Hydro One to the transmission system in the province of Ontario. 526 I believe that the purpose of this change was to expand the definition of transmission customer to include the customers of the other licenced transmitters. It was needed because of the Board's rate order for wholesale pooled transmission rates, which were to be applied to specific named regulated transmitters. 527 I don't believe that the change should be interpreted to expand the definition of transmission customer to those who do not have a direct connection to a licenced transmitter. 528 Now, I have some reason to believe that, which is based upon, first of all, the whole point of the pooling exercise was to expand things to include the other licenced transmitters, but Hydro One, in its submission to the Board, attached a letter which was to be sent by licenced transmitters to their transmission customers, and the Board submitted this letter for approval by the Board. 529 Now, this is also in this exhibit -- 530 MR. SIDLOFSKY: That would be, sir, just to assist the Board, about seven pages in at that tab, at tab H. 531 MR. SNELSON: Yes. 532 MR. SIDLOFSKY: Just past the export transmission service schedule, and you should see a letter dated April 26th, 2002. 533 MR. BETTS: Yes, we have that. 534 MR. SIDLOFSKY: You have that? 535 MR. BETTS: Yes. 536 MR. SNELSON: And one of the attachments to that letter, and you have to go several pages through further on, is titled "a message from -- insert transmitter name -- new rate information." 537 And I point you to the paragraph that says "you are a transmission customer", and it says: 538 "You have been identified as being a transmission customer. A transmission customer has been defined by the Ontario Energy Board as being an entity who owns the facilities that are directly connected to the transmission system owned by a licenced transmitter in Ontario. As a transmission customer you will be subject to all or some of the OEB-approved transmission rates for the specific transmission services you receive from..." 539 And then the transmitter's name is to be inserted. 540 So Hydro One did not interpret the new rates schedule as extending the definition of transmission customer to include parties who did not have a direct connection to a licenced transmitter. And I think, practically speaking, if you extend the idea of a transmission customer to parties that don't have a direct connection to a transmitter, you are creating some ambiguities and uncertainties that make things more difficult. 541 How can a licenced transmitter provide transmission services to a party that is not connected to its system? It may be able to provide a transmission partway, but it can't provide a transmission service the whole way. 542 As discussed later in the evidence, I'll be talking about transmission delivery point, how can a licenced transmitter provide transmission services to a transmission delivery point that it doesn't own and doesn't have operational control of? 543 So I believe that the only self-consistent interpretation of the rates schedule and of the definition of transmission customer is that it should be limited to transmission customers -- transmission customers should be those who have a direct connection to a licenced transmitter and that there should be a consistent definition of transmission delivery point. 544 MR. SIDLOFSKY: And, sir, Hydro One has the definition of delivery point in the April 30th, 2002 transmission rates schedule, and that definition is: 545 "The transmission delivery point is defined as the transformation station owned by a transmission company or by the transmission customer which steps down the voltage from above 50 kV to below 50 kV and which connects the customer to the transmission system." 546 Now, sir, in your opinion is this a suitable definition of transmission delivery point for the application of the tariff, and if it is not, what definition would you recommend be used? 547 MR. SNELSON: This is an adequate definition for most circumstances, but it is not an adequate definition where there is a facility such as the Abitibi facility where there is a reasonably extensive non-licenced transmission facility. 548 This definition is clearly designed for the normal circumstance where there is a Hydro One transformer station, Hydro One or the customer owns the transformation facilities and then there are a number of feeders who are supplied from that transformation station, some of which may go to Hydro One local distribution, and some might go to other local distribution companies, and it is clearly defined for that kind of circumstance. 549 In this particular case, by applying that definition, then all six of the transformers that step down from Abitibi's 115 kV transformation line would become separate transmission delivery points. 550 These facilities have nothing to do with the licensed transmitter. They are entirely the private matter of Abitibi as to what kinds of transformation facilities it wants to have, and yet Hydro One asserts that these are transmission delivery points. 551 The consistent definition of transmission delivery point in a circumstance such as Abitibi's is that the delivery point is the point at which the ownership changes, the point at which Hydro One ceases to be responsible for the delivery of power. 552 This is the point at which Hydro One ceases to provide transmission services. Beyond this point, the non-licensed transmitter -- in this case, Abitibi -- is responsible for providing, maintaining and operating the facilities. As I have said, from a practical point of view, Hydro One provides no transmission services beyond that point. 553 This is also a suitable definition because it conforms to historical practice. We have heard from Mr. Gartshore that in the operating agreement, I believe it is a January 1, 1997, operating agreement between Abitibi Fort Frances and Ontario Hydro, that was defined as the delivery point for the delivery of power from Ontario Hydro to the plant. 554 Under the contract between Westcoast and Ontario Hydro, now OEFC, for the non-utility generation power, that was the deemed delivery point, even for the power that was within the plant. And it is also consistent with the location of revenue metering. We have revenue metering at the Hydro One transformer station, Fort Frances station, that measures the power that goes out on the F2B line to the Abitibi complex. That is the power that is flowing over the system at the point where the ownership changes. 555 To sum up, I believe in these kinds of circumstances, the consistent definition is that transmission customers are those who have direct connections to a licensed transmitter, and the delivery point is the point at which the ownership changes. 556 MR. SIDLOFSKY: Sir, in your view, is the co-generation facility at Fort Frances an embedded generation facility within the meaning of the Board's decision on Hydro One's transmission rates? 557 MR. SNELSON: Yes, it is. As I have read before, the decision defines embedded generation at paragraph 3.2.1. Generation that is not connected to the transmission system and is located behind the meter that registers the electricity supplied from the regulated transmission facilities is referred to as embedded generation. 558 Now, apparently there are two sections to that definition: One is "not connected to the transmission system"; and the other is being "behind the meter that registers the electricity supplied from the regulated transmission system." 559 There is no doubt that the Westcoast or Abitibi co-generation facility is behind the meter that registers the flow from the regulated transmission system. That is the meter in the Hydro One transformer station on the supply end of the F2B line. 560 Now, Hydro One argues that these two parts of this definition are separate and they have to be separately met and that the first one says that the generation is not connected to the transmission system. Now, it is not clear from the Board's decision, because regulated and unregulated transmission hadn't really been defined at that point in time, whether that reference is to the not connected to the transmission system, any transmission system, any facilities over 50 kV, or whether it is not connected to the regulated transmission system. 561 And in my view, the only reasonable interpretation is that it is not connected to the regulated transmission system. 562 Now, Hydro One is proposing that the other interpretation, and that is one of the parts of their case, and I would point you to Hydro One's own definition of embedded generation at the time of the transmission rate hearing. This is in their submission to the transmission rate hearing, Exhibit D, tab 5, schedule 1. And do we have copies of that? 563 MR. SIDLOFSKY: We do, sir. This was filed as part of the package that included the administrative instruction NW-150 and the spreadsheet. I have separate copies, though, if it would help the Board. 564 MR. BETTS: That would be helpful. 565 MR. SNELSON: And this is schedule 1, page 5, lines 1 to 6. 566 MR. MORAN: Mr. Chair, perhaps before Mr. Snelson continues, we can mark this as an exhibit. 567 MR. BETTS: That's fine. 568 MR. MORAN: This will become Exhibit 1.6; it is an excerpt from a filing in the RP-1999-0044 proceeding, entitled "Net Load Billing Versus Gross Load Billing". 569 EXHIBIT NO. 1.6: EXCERPT FROM A FILING IN THE RP-1999-0044 PROCEEDING, ENTITLED "NET LOAD BILLING VERSUS GROSS LOAD BILLING" 570 MR. BETTS: Thank you. 571 MR. SNELSON: And as I have said, lines 1 to 6 there has a definition of embedded generation, and it says: 572 "The generation that is not connected to the transmission system is defined as embedded generation. For the purposes of this schedule, this term refers to generation that is located behind the meter that registers the electricity supplied from the regulated transmission facilities." 573 If you read those words very carefully, this is not a two-part test in Hydro One's view. This is an initial statement and then a clarification of what the initial statement means. There is no doubt that with that definition of embedded generation, the Fort Frances co-generation facility is behind the meter that registers the power delivered from the regulated transmission facilities. It is clearly an embedded generator. 574 So as I have said, for a whole host of reasons we have been through, I am of the view that this is an embedded generator within the meaning of the transmission rate order. 575 MR. SIDLOFSKY: Thank you, sir. If the Board adopts your views as to the definition of transmission customer, transmission delivery point and embedded generation, will that lead to any large-scale erosion of Hydro One's transmission revenues as increasing numbers of closely-located loads and generators claim net load billing? 576 MR. SNELSON: No, I don't believe this will have a large impact. Hydro One in its evidence raises the spectre of what I call the slippery slope, as loads that are located close to generators seek to be recognized as having net load billing and that there is a gradual erosion, maybe rapid erosion of loads that are paying the transmission tariff and therefore that adversely affects the transmission users and the effect on the transmission rate. 577 What is being discussed here in my evidence here is with respect to the interpretation of the existing rate order in a very specific circumstance, and that we are seeking -- or I am proposing that the existing rate order should be interpreted in the way that I have described. 578 There are only a very few cases where there are unlicensed transmission facilities that could lead to similar treatment, and so the impact on the transmission revenues would be relatively small. You couldn't have an unrelated load connected to a Hydro One transmission line and an unrelated generator connected to the same transmission line owned by Hydro One a few miles away saying, "Oh, but we are all together, we should be given net load billing." 579 That is not what the rate order said. That is not going to happen if you accept that Abitibi is an embedded generator. 580 MR. SIDLOFSKY: Sir, I know from your comments that you have had a chance to take a look at Hydro One's responses to the Abitibi interrogatories, and are you aware of whether Hydro One identified any other situation in the province that was identical to Abitibi? 581 MR. SNELSON: I don't believe there is any other situation that is exactly identical. 582 MR. SIDLOFSKY: Sir, those are my questions, thank you. 583 MR. BETTS: Thank you, Mr. Sidlofsky. 584 I think at this point we will break for an hour for lunch, and we can return with cross-examination of these witnesses. 585 So we will adjourn now and return let's make it at 1:45. 586 --- Luncheon recess taken at 12:40 p.m. 587 --- On resuming at 1:46 p.m. 588 MR. BETTS: Welcome back, everybody. Before we begin cross-examination of this witness panel, are there any preliminary matters? 589 I believe, then, we'll begin cross-examination with Mr. Moran, so he can fill in the record for the Board, and then we will go on from there. 590 Mr. Moran. 591 CROSS-EXAMINATION BY MR. MORAN: 592 MR. MORAN: Thank you, Mr. Chair. 593 Panel, perhaps I could get you to turn up first Exhibit 1.2, tab B.1.2 is the binder with your witness statements in it. 594 MR. SIDLOFSKY: Sorry, was that B as in Bob? 595 MR. MORAN: Yes, that is the simplified diagram, the same one as we see enlarged on the stand over here. 596 I just wanted to clarify a couple of the ownership issues, and then I'll move on. 597 In looking at this diagram then, as I understand it, at the top you have got the Hydro One 8th Street station, right, Mr. Gartshore? 598 MR. GARTSHORE: Yes, that's correct. 599 MR. MORAN: And if we follow the line down, we have got F2B, which is the line connection to the Abitibi Consolidated complex? 600 MR. GARTSHORE: Yes. 601 MR. MORAN: And the point of connection for F2B to the Abitibi equipment is where we see the square box marked "F2B-BKR"; right? 602 MR. GARTSHORE: That's correct. 603 MR. MORAN: Okay. And that is a reference to breakers or some kind of switch yard there? 604 MR. GARTSHORE: There is actually dead-end insulators right above that breaker, which is where the termination point is. 605 MR. MORAN: Right. And the dead-end insulators are the point that you say is the end of the Hydro One transmission system and the beginning of the Abitibi Consolidated transmission system; right? 606 MR. GARTSHORE: That's correct. 607 MR. MORAN: And for purposes of your case, you say that is the delivery point that is relevant? 608 MR. GARTSHORE: Yes. 609 MR. MORAN: All right. All right, and then everything that we see that is in red are facilities, high-voltage facilities that belong to Abitibi Consolidated? 610 MR. GARTSHORE: The transformers at the co-gen site, T-1 and T-2 are part of the co-gen facility and belong to Westcoast at the present time, but the other four belong to Abitibi. 611 MR. MORAN: Okay. So T-1 and T-2 belong to WCP, Westcoast Power, as part of the co-gen plant? 612 MR. GARTSHORE: That's correct. 613 MR. MORAN: Okay. And then there is an interconnect there with the Abitibi Consolidated transmission line? 614 MR. GARTSHORE: Correct. 615 MR. MORAN: All right. And then if we look at the bottom left-hand corner, there is another generator, that is the hydraulic generator that you have been talking about; right? 616 MR. GARTSHORE: Yes, those are the small hydraulic generators, there's eight of them there. 617 MR. MORAN: And that is directly owned by Abitibi? 618 MR. GARTSHORE: Directly owned by Abitibi. 619 MR. MORAN: All right. And as I understand Abitibi's case, there is no debate about who actually owns F2B, the line that you identified as belonging to Hydro One. The issue is whether Abitibi-Consolidated or its predecessor contributed a payment for the construction of that line; right? 620 MR. GARTSHORE: That's correct. We never purported to own the line. We think we have contributed fully to its construction. 621 MR. MORAN: Okay. All right, now with respect to the co-gen that is owned by WCP, you have indicated that it is owned by WCP, but it is operated by Abitibi Consolidated; right? 622 MR. GARTSHORE: Yes. 623 MR. MORAN: And then just to understand all the arrangements around the co-generator, WCP is the successor to the person who originally owned the co-gen, right, ICG? 624 MR. GARTSHORE: ICG, that's right. 625 MR. MORAN: And ICG had a power purchase agreement with the old Ontario Hydro; right? 626 MR. GARTSHORE: Yes. 627 MR. MORAN: Okay. So WCP took over ownership from ICG; right? 628 MR. GARTSHORE: That's correct. 629 MR. MORAN: And Ontario Hydro on the other side of the contract was replaced by OEFC? 630 MR. GARTSHORE: Yes. 631 MR. MORAN: All right. So WCP owns the output and gets paid for the output from the co-gens by OEFC? 632 MR. GARTSHORE: Yes. 633 MR. MORAN: Right. And in the meantime, WCP is not actually running the station, that's done by Abitibi-Consolidated? 634 MR. GARTSHORE: Yes, we operate it and maintain it. 635 MR. MORAN: All right. And I assume when you say that, you mean you are operating it on behalf of WCP; right? There is some sort of agreement between WCP and Abitibi-Consolidated? 636 MR. GARTSHORE: Yes, there is an operations and maintenance agreement that spells it out. 637 MR. MORAN: And WCP essentially pays Abitibi to run the station; right? 638 MR. GARTSHORE: Yes, they do, that's correct. 639 MR. MORAN: All right. So is it like an annual fee or is it related to the purchase agreement? 640 MR. GARTSHORE: It is related to the actual hours. There is charge-out rates for the number of hours we spend in there, and on average there is 8 to 10 people involved in operating and maintaining the plant. 641 MR. MORAN: Okay. So it is intended to cover the costs of running the plant, that is the arrangement that you have with WCP? 642 MR. GARTSHORE: That's the arrangement, yes. 643 MR. MORAN: So because you are actually running it, you are generating the electricity, and that's why you have a licence; right? 644 MR. GARTSHORE: Correct. 645 MR. MORAN: And the licence, what falls out of that is that you are a market participant, as far as the IMO is concerned, for the purposes of dispatch; right? 646 MR. GARTSHORE: For purposes of generation. 647 MR. MORAN: Yes. You are not selling the power; you are not doing anything on the market side; you are simply running the station on the physical side? 648 MR. GARTSHORE: That's correct. 649 MR. MORAN: And does Abitibi-Consolidated have an operating agreement with the IMO? 650 MR. GARTSHORE: Yes. 651 MR. MORAN: For that generator? 652 MR. GARTSHORE: Yes. 653 MR. MORAN: All right. And under the terms of that agreement, I assume that that allows the IMO to tell you when to run and when not to run, etc., the usual kind of operating agreement that the IMO has with generators? 654 MR. GARTSHORE: Yes, with any generator. 655 MR. MORAN: All right. Now, you indicated that also part of the arrangements with WCP is Abitibi Consolidated's right to purchase the generating station, the co-gen? 656 MR. GARTSHORE: Yes. 657 MR. MORAN: And is that something that was inherited by Abitibi-Consolidated as a result of it taking up where Boise Cascade left off, or is this a new contract or new agreement directly negotiated by Abitibi-Consolidated? 658 MR. GARTSHORE: No, It is from the original agreement, and Abitibi assumed all the original agreements and responsibilities. 659 MR. MORAN: All right. So back when the co-generation station was being planned and all the agreements were being entered into, one of the agreements had to do with the eventual purchase of the station from ICG by Boise Cascade, who were the entities in existence at that time; right? 660 MR. GARTSHORE: Yeah, it is clearly spelled out and the dollar value with the different years. It allows for force majeure as well. 661 MR. MORAN: And if you wait long enough, as I understand it, 'til 2008, the purchase price is a dollar; if you don't want to wait that long, you would pay more than that? 662 MR. GARTSHORE: Yes, a sliding scale, basically. 663 MR. MORAN: All right. So part of the original arrangement then, just to make sure I have it right, Boise Cascade and ICG have an agreement to cover the eventual purchase of the station from ICG; right? 664 MR. GARTSHORE: That's correct. 665 MR. MORAN: Boise Cascade became Abitibi-Consolidated? 666 MR. GARTSHORE: Yes. 667 MR. MORAN: ICG became WCP and that agreement continues under the new names, all right. 668 Presumably there is also an agreement between Boise Cascade and ICG for the steam sales? 669 MR. GARTSHORE: Steam and energy, yes. 670 MR. MORAN: Were the steam sale agreements separate from the energy? 671 MR. GARTSHORE: I believe there is three or four different agreements, but they all went together at the time of the construction. 672 MR. MORAN: All right. But the energy agreement was actually with Ontario Hydro; right? 673 MR. GARTSHORE: Yeah, when I say steam and energy, there was actual steam from the mill that goes into the co-gen plant, we send them steam at 875 pounds per inch, that is coupled with the steam in the co-gen and then goes through the steam turbine, so we do supply energy in the form of steam to co-gen and then we buy steam back, low-pressure steam back from co-gen, so they didn't deal with power. It didn't deal with electricity. 674 MR. MORAN: So there is a two-way flow of steam, as it were. There is steam that is provided from the co-gen plant to the paper mill and so on, and then there is steam back from the paper mill to the co-gen to be used for the generation of electricity. 675 MR. GARTSHORE: Yes. 676 MR. MORAN: Okay. Now, you indicated that in the year 2008, the only thing that would change is the name of the owner. But as I understand it, the NUG contract, the power-purchase agreement, also ends in 2008; right? 677 MR. GARTSHORE: Yes, it does. 678 MR. MORAN: All right, so at that point there is a number of options available to Abitibi. They'll own the plant, one way or another, by the year 2008 and they could operate it the same way as they operate the hydraulic station; right? 679 MR. GARTSHORE: Yes. 680 MR. MORAN: And at that time, you wouldn't be committed to selling the power to anybody at all; right? 681 MR. GARTSHORE: We could use it for our own internal needs, which would probably be the case, and we could sell the excess. 682 MR. MORAN: And then sell the surplus, right. And presumably the physical arrangement, of course, is the same; as you have indicated, the co-gen provides the load for the mill side and the surplus goes out into the grid. It is just the financial arrangements could change; right? 683 MR. GARTSHORE: Yes. 684 MR. MORAN: In 2008. Okay. Now, is the mill an interruptible load? 685 MR. GARTSHORE: No. 686 MR. MORAN: It is a firm load. So the 75-megawatt load always has to be met; it can't be interrupted by the IMO? 687 MR. GARTSHORE: Not any more. 688 MR. MORAN: Not any more, okay. When did that arrangement stop? 689 MR. GARTSHORE: Well, with the deregulation, we buy power, and if we want to stay on, we have to buy. We have to pay the going rate. 690 MR. MORAN: Okay, so you are not interruptible load at all anymore since market opening? 691 MR. GARTSHORE: Not to my understanding, no. 692 MR. MORAN: All right. Do you know for sure? 693 MR. GARTSHORE: I am not sure. 694 MR. MORAN: All right. Perhaps you could find out and give an undertaking to provide that information. 695 MR. GARTSHORE: Certainly. We were interruptible under the DDS rates at previous times, and we never were interrupted, so I am not certain whether we still are or not. 696 MR. MORAN: Mr. Chair, that would be Undertaking 1.1, an undertaking to confirm if Abitibi-Consolidated is still an interruptible load or not. 697 UNDERTAKING NO. U.1.1: TO CONFIRM IF ABITIBI-CONSOLIDATED IS STILL AN INTERRUPTIBLE LOAD 698 MR. BETTS: Just for clarification, should we establish a prefix for the undertakings? 699 MR. MORAN: Sorry, I forget to say U.1.1. 700 MR. BETTS: U.1.1, thank you. 701 MR. MORAN: Okay, just to finish this point out, you indicated that previously Abitibi was an interruptible load, but you were never interrupted, as far as you know. 702 MR. GARTSHORE: As far as I know. 703 MR. MORAN: All right. Now, Mr. Gartshore, I would like to turn you to your witness statement now, which is before tab "A" in the same exhibit, 1.2. If you could turn to page 2 of your witness statement. In the top paragraph there, you describe some of the arrangements between the relevant parties and as I understand the evidence that you have just given to various questions I just asked you, all of the contractual arrangements between WCP and Abitibi-Consolidated and OEFC are essentially the same arrangements that were in place when the co-gen was first established. 704 MR. GARTSHORE: That's correct. 705 MR. MORAN: Okay. All right, then turning to the second paragraph at the top of that page, you indicate that Abitibi-Consolidated is a generator as that term is defined in the OEB Act and in Abitibi-Consolidated's generator licence, because it owns or operates generation facilities. 706 And if I understand the licence or if I recall the licence format correctly, you would have a schedule attached to your licence that would list the various generation facilities that you operate and the reason you said own or operate is because the hydraulic station is on that list, and you own that one. And the co-gen is on that list but you don't own it, you operate that one. 707 MR. GARTSHORE: That's correct. 708 MR. MORAN: Are there other generating facilities on that schedule? 709 MR. GARTSHORE: Yes, there are. 710 MR. MORAN: And those are located elsewhere in the province? 711 MR. GARTSHORE: Elsewhere in the province. The schedule is at tab A. 712 MR. MORAN: All right. Thank you. All right, now I think you have indicated that the Abitibi load is about 75 megawatts; right? 713 MR. GARTSHORE: Yes. 714 MR. MORAN: And the concern that you have brought to the Board is the fact that you are billed on the basis of taking 75 megawatts off the transmission system when in fact most -- in fact all of that load is met by the co-gen and the hydraulic station; right? 715 MR. GARTSHORE: Yes. 716 MR. MORAN: Okay. 717 MR. GARTSHORE: The hydraulic station is netted out, I should be clear there. The total load is 75, which would include the hydro station, but our bill, the hydro station comes out because it was existed -- existed embedded generation. 718 MR. MORAN: So when you talk about the Abitibi load being 75 megawatts, this is after subtracting the 10 megawatts for the hydraulic station. 719 MR. GARTSHORE: Yes, it is total. 720 MR. MORAN: So the 75 megawatts then, the remaining 75 megawatts is met totally by the co-gen? 721 MR. GARTSHORE: Yes -- 65, I am confusing you. The total load facility is 75. The hydraulic generator produces roughly 10, anywhere from 5 to 10 depending on water conditions. The rest is met by the co-gen plant, so it could be 65 to 70 megawatts. 722 MR. MORAN: All right, I thought that's the way it was, and then I misunderstood your next answer. 723 MR. GARTSHORE: I am not helping at all. 724 MR. MORAN: No problem. So the 75 megawatt is the total load for Abitibi-Consolidated, -- 725 MR. GARTSHORE: Yes. 726 MR. MORAN: -- leaving aside any generation? 727 MR. GARTSHORE: Right. 728 MR. MORAN: All right, and then 10 megawatts of that load is met by the hydraulic station, the balance is met by the co-gen, and in the event that the co-gen isn't able to meet that, then you take power from the transmission system. 729 MR. GARTSHORE: Correct. 730 MR. MORAN: All right. And as I understand it, Hydro One bills you for the load net of the 10 megawatts of hydraulic generation? 731 MR. GARTSHORE: That is my understanding, yes. 732 MR. MORAN: All right. But not net of the remaining 65? 733 MR. GARTSHORE: Correct. 734 MR. MORAN: All right. So when you indicate that you are being billed on a gross load basis rather than a net load basis, it is with respect to 65 megawatts of the 75 megawatts of load, because the rest is met by the 10 and Hydro One does net that out. 735 MR. GARTSHORE: Correct. 736 MR. MORAN: Now, if you could turn up Exhibit 1.1, tab D, that is where the original power purchase agreement is to be found. At page 3 of the agreement, you'll see section 1 which sets out some definitions. 737 MR. GARTSHORE: Mm-hm, yes. 738 MR. MORAN: Definition 1.1 for general power says that: 739 "General power means the power delivered by Hydro to ICG Ontario under the conditions in schedule B at the delivery point to supply ICG Ontario's internal load requirements that cannot be supplied by internal generation. For billing purposes, the quantity of general power shall be measured at the metering point." 740 I take it that what that is referring to is if the co-generation plant is down, there is still a need for power at the co-gen plant for lighting and so on, and that is what the reference is to general power; it is backup power, in other words? 741 MR. GARTSHORE: It would apply to, as you said, lighting and station-service type loads. 742 MR. MORAN: Yes, all right. Now, do you know what the load is for the co-gen? 743 MR. GARTSHORE: When it is not running, the station service load? 744 MR. MORAN: Yes. 745 MR. GARTSHORE: I would be guessing it would be very low, 200 kilowatts, .3 of a meg, perhaps. 746 MR. MORAN: And how is Abitibi-Consolidated billed for that load? 747 MR. GARTSHORE: I don't know. 748 MR. MORAN: So you don't know if it is on a gross or a net basis? 749 MR. GARTSHORE: Gross or net, no, I don't. 750 MR. MORAN: Could you perhaps undertake to confirm which it is? 751 Mr. Chair, that would be Undertaking U.1.2, to confirm whether the co-gen is billed on a gross-load or a net-load basis. 752 UNDERTAKING NO. U.1.2: TO CONFIRM WHETHER ABITIBI'S CO-GENERATION IS BILLED ON A GROSS-LOAD OR A NET-LOAD BASIS 753 MR. BETTS: Thank you. 754 MR. MORAN: Either way, because Abitibi is the operator, that would be a bill that Abitibi would pay; right? 755 MR. GARTSHORE: On behalf of the co-gen plant, yes. 756 MR. MORAN: Because you are responsible for service and maintenance and whatever it costs to do that; right? 757 MR. GARTSHORE: We can find out how that is billed. It wouldn't be very often, but... It runs most of the time. 758 MR. MORAN: All right, now turning back to your witness statement at page 3, that is at Exhibit 1.2 before tab A. You have got a section that is headed up at the bottom of the page there, Section 3, "Is Westcoast power obligated to supply Abitibi-Consolidated"; do you have the reference? 759 MR. GARTSHORE: Page 3? 760 MR. MORAN: Page 3 of your witness statement. 761 MR. GARTSHORE: Which paragraph? 762 MR. BETTS: That is page 4 on mine, Section 3, I believe. 763 MR. GARTSHORE: Yeah, it is Section 3 on page 4. 764 MR. MORAN: Okay, the numbering on mine is page 3, I don't know if I have the same one. 765 MR. GARTSHORE: "Is Westcoast power obligated to supply Abitibi-Consolidated"? 766 MR. MORAN: That's correct, yeah. It looks like the formatting on mine has single spacing instead of double spacing. 767 Anyway, you have the section I am looking at, Section 3, "Is Westcoast power obligated to supply Abitibi-Consolidated?" 768 And you indicate that the answer is yes, based on the agreement, and then you make reference to 5.1 of the agreement. 769 MR. GARTSHORE: Mm-hmm. 770 MR. MORAN: If we could just turn back to the agreement then, I have a couple of questions about 5.1, but before I ask you about that, I would like to explore Section 5. The agreement is set out at tab D of Exhibit 1.1 at page 8. 5.0 says: 771 "ICG Ontario shall sell and, subject to 5.1, deliver capacity power exclusively to Hydro, which capacity power shall be measured at the metering point. 772 Do you see that, Mr. Gartshore? 773 MR. GARTSHORE: No. What page are you on in the agreement? 774 MR. MORAN: Page 8 in the agreement, Section 5, 5.0. 775 MR. GARTSHORE: Okay. 776 MR. MORAN: All right, so now we have WCP in place of ICG Ontario; right? 777 MR. GARTSHORE: Mm-hmm. 778 MR. MORAN: And to understand what capacity power is, we have to go to the definition section, so if you could turn back to page 3 of the agreement, Section 1.0, and we see a definition for capacity power there at 1.0. 779 MR. GARTSHORE: Mm-hmm. 780 MR. MORAN: And it says: "Capacity power means the net power delivered to Hydro by ICG Ontario at the delivery point or deemed to be delivered as described in Section 5.1 after internal load requirements at the co-generation facility are met." Right? 781 MR. GARTSHORE: Okay. 782 MR. MORAN: So what that means is that whatever the co-gen needs for lighting and service needs is subtracted by the rest makes up what is called capacity power; right? 783 MR. GARTSHORE: Mm-hmm. 784 MR. MORAN: And if we were to put together the two definitions for capacity power at 1.0 and general power at 1.1, the capacity power is basically what's left of the total power output after you subtract general power; right? 785 MR. GARTSHORE: Mm-hmm, yes, I agree. 786 MR. MORAN: All right. Now, you'll agree that that definition doesn't include any description or amount that would be attributable to the load for the mill; right? 787 MR. GARTSHORE: No, it doesn't, but it goes on in 5.1 to -- 788 MR. MORAN: Right, and we'll get to 5.1 in a minute. 789 MR. GARTSHORE: Okay. 790 MR. MORAN: One step at a time. 791 All right, so back to 5.0, ICG, now WCP, agrees to deliver capacity power exclusively to Hydro, and the reference to Hydro, of course, is Hydro One; right? 792 MR. GARTSHORE: Mm-hmm. 793 MR. MORAN: So again, there is no reference to Boise Cascade or Abitibi now; right? Is that right? 794 MR. GARTSHORE: No, there is none. 795 MR. MORAN: Okay, so the capacity power has to be delivered to Hydro, and it is measured at the metering point. To understand what the metering point is, we have to go back to the definitions; right? And as I understand the definition of the metering point, if you want to just check the definition, it's what is read on the meters that are located at the co-gen; right? 796 MR. GARTSHORE: That's my understanding. 797 MR. MORAN: All right, the definition is on page 5, it is at 1.13, the definitions are not alphabetical. Do you have the definition? 798 MR. GARTSHORE: For metering point? 799 MR. MORAN: Yes. 800 MR. GARTSHORE: No, I don't. 5 point what? 801 MR. MORAN: It is on page 5, Section 1.13. 802 MR. GARTSHORE: Yes, I have it now. 803 MR. MORAN: And there is a reference to the metering equipment installed by hydro on the low-voltage side, so just to confirm, those are the two meters that we see next to the co-gen plants on the low-voltage side in the diagram? 804 MR. GARTSHORE: Yeah, those are the ones. 805 MR. MORAN: Okay, and those were installed by Hydro, as far as you know? 806 MR. GARTSHORE: As far as I know, they were installed by Ontario Hydro. 807 MR. MORAN: Okay. All right, so going back then to Section 5.0. The next sentence says: "Subject to the provisions of this agreement, including without limitation provisions deemed necessary by Hydro to ensure system safety, security and reliability, Hydro agrees to purchase all capacity power measured at the metering point up to a maximum of 100,000 kiloWatts at all times during the term of this agreement." 808 So this is the flip side of the arrangement: The first sentence says that ICG shall sell the capacity power, and this sentence that we are just looking at now says that Ontario Hydro will purchase that power, right, up to a maximum of 100,000 kiloWatts at all times; right? 809 MR. GARTSHORE: Yes. 810 MR. MORAN: Okay, so again, there is no mention of the load being involved in this; right? 811 MR. GARTSHORE: Not yet, no. 812 MR. MORAN: And then the next sentence goes on to say that: "Hydro may agree from time to time to accept capacity power in excess of 100,000 kiloWatts, but not exceeding 120,000 kiloWatts, at any time." 813 What is the thinking behind that arrangement? Is this to allow for power that isn't being used temporarily by the load? 814 MR. GARTSHORE: No, I think it is more related just to the nature of the co-gen plant where in the winter they tend to produce more power, so when we say 100, we are saying 100 on average. In the summer, it tends to dip because the air is warmer and in the winter it is higher, and I think at the time Hydro didn't want to purchase any more than that. 815 MR. MORAN: So the co-gens operate more efficiently when the weather is cold and that is recognized in that upper limit of 120,000, but that was the most that Ontario Hydro was prepared to commit to? 816 MR. GARTSHORE: That is my understanding. 817 MR. MORAN: All right. And then finally the last sentence: "Subject to Section 4.1 this agreement provides ICG Ontario with an opportunity, but not an obligation, to deliver capacity power to Hydro pursuant to the terms. 818 What does that mean? 819 MR. GARTSHORE: Well, I would say that I am not exactly sure what it means, but the way I interpret it is they are not obligated to provide the 100 megawatts all the time, but there is an opportunity there to sell it. So there is no recourse on them if they don't provide it. 820 MR. MORAN: Right, the co-gen might have to shut down sometimes, and if they do, they do, and they haven't breached any obligation to provide that power for sale; right? 821 MR. GARTSHORE: That is my understanding. 822 MR. MORAN: All right. And then there is a reference to 4.1. And if you look at 4.1 on page 7, as I understand it, it allows Ontario Hydro to terminate the arrangement if there is a failure to supply power for an extended period of time, notwithstanding that there is no obligation? 823 MR. GARTSHORE: Yeah, 12 months I think. 824 MR. MORAN: That's right. All right, and then that takes us then to 5.1, which says: 825 "To the extent that ICG Ontario is delivering capacity power, ICG Ontario shall deliver capacity power directly to Boise Canada from time to time on behalf of Hydro and deliver the balance of capacity power to Hydro at the delivery point." 826 As I understand what is being said here, and correct me if I am wrong, because Boise Canada is next door and because it has a load that would otherwise have to be served directly by Ontario Hydro, ICG will serve that load on behalf of Ontario Hydro; right? 827 MR. GARTSHORE: I think at the time the only entity that could purchase or sell power in Ontario was Ontario Hydro, and with the physical setup of the complex, the power has to go into the mill first to get out, so I think this was an attempt to reflect the reality of power flows. 828 MR. MORAN: Right. 5.0 says that ICG will deliver all the capacity power to Hydro, and 5.1 says it will deliver power to Boise Canada on behalf of Hydro; right? 829 MR. GARTSHORE: That's what it says. 830 MR. MORAN: Right. Then it goes on to say: 831 "The quantity of such capacity power delivered to Boise Canada shall be the amount of capacity power measured at the metering point minus the amount of capacity power measured at the delivery point"; right? 832 MR. GARTSHORE: Correct. 833 MR. MORAN: Now, the metering point, we already understand what that is. The metering point are the meters at the co-generation plant; right? 834 MR. GARTSHORE: That's right. 835 MR. MORAN: And the reference to delivery point is a defined term, and we can find that on page 5 of the agreement in section 1.11, and that's where we see the reference to Ontario Hydro's line dead-ending insulators as being designated as the delivery point; right? 836 MR. GARTSHORE: Yes. 837 MR. MORAN: And that is the delivery point that is located if we look at the diagram, at the end of the F2B line; right? 838 MR. GARTSHORE: Yeah, it is the yellow square on the aerial photo. 839 MR. MORAN: The yellow line or box on the aerial photograph, and that is the point where Abitibi's high-voltage equipment starts and Ontario Hydro's, now Hydro One's, high-voltage equipment ends; right? 840 MR. GARTSHORE: Yes. 841 MR. MORAN: Now, that point is actually located on Abitibi-Consolidated property; right? 842 MR. GARTSHORE: Yes, it is. 843 MR. MORAN: All right. So going back to 5.1: "The quantity of such capacity power delivered to Boise Canada shall be the amount of capacity power measured at the metering point minus the amount of capacity power measured at the delivery point"; right? 844 MR. GARTSHORE: Yes. 845 MR. MORAN: "Such power delivered to Boise Canada shall be deemed to be delivered at the delivery point provided that such capacity power is received by Boise Canada." 846 So what that means is that notwithstanding the physical flow of power that would have to happen to get power from the co-gen to Boise, delivery is deemed to happen at that yellow box on the aerial photograph, right, at the end of Hydro One's transmission system? 847 MR. GARTSHORE: Yes. 848 MR. MORAN: And then finally it says: 849 "ICG shall guarantee that all capacity power measured at the metering point shall be delivered or deemed to be delivered to Ontario Hydro at the delivery point." Right? 850 MR. GARTSHORE: Yes. 851 MR. MORAN: So what that means is it is just simply reconfirming the fact that the delivery point is the end of the transmission system now owned by Hydro One, regardless of the physical flow; right? 852 MR. GARTSHORE: Mm-hm. 853 MR. MORAN: So in effect when we look at 5.0 and 5.1 what we see is the result of a financial transaction rather than a physical transaction; is that fair? 854 MR. GARTSHORE: Yeah, I would say it is financial, not physical. And it was a notional attempt to try and create a generator and a load, I guess. 855 MR. MORAN: Right, and it is exactly the same financial arrangement that exists today; right? 856 MR. GARTSHORE: Yes. 857 MR. MORAN: Now, before we leave 5.1, I just want to go back to the first sentence and focus in on the phrase that is there "from time to time". Am I correct in understanding that what that means is that, subject to Ontario Hydro's needs for the power, it would be delivered to Boise Cascade? 858 MR. GARTSHORE: I am not sure. I interpret that as supplying power to Boise Cascade because it can't go anywhere else, it can't get out without supplying the mill loads first and -- 859 MR. MORAN: Back when this arrangement was first entered into, Boise Cascade was an interruptible load, though, wasn't it? 860 MR. GARTSHORE: That -- probably, yeah, parts of that time. 861 MR. MORAN: Right, so if the electricity was to be delivered to Ontario Hydro and for system needs Ontario Hydro decided that it needed the power more than Boise Cascade, it could interrupt Boise Cascade and take that power into the system; right? 862 MR. GARTSHORE: It could, but the trouble is, the way the co-gen plant is integrated into the mill, you would have to do something with the steam. So if the mill is not running, you reduce the output of the co-gen plant. So Hydro never -- that's why I had trouble with "interruptible" before. Hydro never wanted to do that because they would basically lose all the power, not get 100; they would lose 25, you understand what I am saying? It is difficult to run the co-gen plant without the mill in tandem, so we shut the mill down, we lose a big chunk of the co-gen plant and a big chunk of the power. So it was never done. 863 MR. MORAN: Right, and given where it is located, it may not have been needed. 864 MR. GARTSHORE: It may not have helped anyhow, so ... 865 MR. MORAN: Right, okay. 866 I would like to turn now to your Exhibit 1.5, which was the spreadsheet that shows the gross load billing compared to the net load billing. 867 MR. GARTSHORE: Hm-mm. 868 MR. MORAN: And just so I can understand the information that's available in this exhibit, when we look on the left-hand side under the heading "Billed on Gross Monthly Charges", are these basically the actuals that have been billed? 869 MR. GARTSHORE: Yeah, to our knowledge, these are the actuals. 870 MR. MORAN: And then on the right-hand side under the heading "Calculated on Net Monthly Charges", how did you generate those numbers? 871 MR. GARTSHORE: Well, there is a bit of a definition at the bottom. So what we tried to do was, the values were calculated, were based on power-flow measurements using our internal metering for the values on the internal metering of the F2B at the 120 kV line where it enters the mill site. 872 So what we tried to do was go back and reconstruct what it would have looked like had we been billed on a net versus a gross basis, and you could argue that they are not accurate because we would probably have taken steps to reduce our load. Say the co-gen plant had tripped out; we probably would have taken steps by shutting the mill down perhaps or by taking an outage. 873 So it was an attempt to show that if we had been billed on net versus gross, this is what the numbers would look like. 874 MR. MORAN: All right. 875 MR. GARTSHORE: And it also was to try and limit the claim, like the full value is roughly 2 million a year, but I don't think it would ever be 2 million in any year. The co-gen plant would have to run perfectly with no hiccups to allow us not to take power from the line. So it is an estimate, I guess. 876 MR. MORAN: All right, so the net monthly charges on the right-hand side can be characterized as an estimate? 877 MR. GARTSHORE: Most definitely. 878 MR. MORAN: And just looking at the June 2002 line, I note that on the gross side the total is $232,432.53, and on the net side the number seems to be higher, $235,292.51. 879 MR. GARTSHORE: Yeah, I think it is because of the loads at the time and the coincident peaks versus non-coincident peaks. I think it was just a rough estimate to try and get at a typical year. 880 MR. MORAN: Okay. Because normally you would expect the net to be either -- 881 MR. GARTSHORE: We expect them to be about the same. 882 MR. MORAN: -- equal to or less than. All right. 883 MR. GARTSHORE: So I would use this as an estimate, and it is attempting to show there would be months, in fact many months, probably three or four a year, where the complex would be taking power from Hydro One. 884 MR. MORAN: All right. Presumably, if there was a need to verify the net numbers, that could be done through the IMO since they are responsible for calculating what the bill is; right? 885 MR. GARTSHORE: And I think we would have to do something like that to arrive at numbers that both sides could agree to, and the IMO would be the most fair to do it. 886 MR. MORAN: You didn't consult with the IMO to generate these numbers, that was just using meter readings? 887 MR. GARTSHORE: Yeah, and trying to generate the data ourselves to show what it could look like. 888 MR. MORAN: All right. Turning to you, Mr. Snelson, if I were to try to characterize the overall basis of the case that Abitibi wants to make, would it be fair to say that essentially it turns on whether the co-gen should or should not be treated as an embedded generator, is that the heart of the issue? 889 MR. SNELSON: I believe so, yes. 890 MR. MORAN: All right. 891 Mr. Gartshore, did Abitibi participate in the 0044 proceeding, do you know? 892 MR. GARTSHORE: I don't think so. I am not aware of it. What was the 0044? 893 MR. MORAN: That was the case that gave rise to the rate order that you are complaining about. 894 MR. GARTSHORE: Okay. 895 MR. MORAN: So to your knowledge, Abitibi didn't participate in the -- 896 MR. GARTSHORE: Well, we might have through AMPCO. 897 MR. MORAN: So you are a member of AMPCO? 898 MR. GARTSHORE: Yes. 899 MR. MORAN: And they certainly did participate. All right. 900 MR. BETTS: While counsel is considering other questions, the Board recognizes that later in the afternoon, as the sun swings over to the west, this room can get very hot. We will not object if somebody wants to remove their jacket to be a little more comfortable. 901 MR. MORAN: Mr. Gartshore, I would like to take you back to Exhibit 1.5, just a couple more details to understand from this exhibit. Looking at the -- I guess we could look at the November line for 2002. 902 MR. GARTSHORE: Okay. 903 MR. MORAN: On the gross side there is the actual billing for network and line connection and a total for $258,421. 904 MR. GARTSHORE: Mm-hmm. 905 MR. MORAN: And then your estimate on what it would be if it was net shows network charges in the order of $17,000, line connection charges in the order of $63,000, for a total of about $80,000. 906 I wonder if you could describe what the operating conditions were at that time that would give rise to those very different sets of numbers? 907 MR. GARTSHORE: That was the estimate? 908 MR. MORAN: Yes. Now, on the gross side, obviously, that is reflected by the size of the load, so there is no misunderstanding there, but what would lead to a very small net monthly charge, what operating conditions are prevailing at that time? 909 MR. GARTSHORE: Well, I think the way the spreadsheet was prepared, it included some other -- it is our total bill from -- I guess our total electricity bill, so it includes some other charges we have for power that is not related to the mill. And I think it involves the town of Fort Frances and the lagoon. So I think there is a net load that is not attached to the complex but still in the same town that shows up on our bill. I think the way this was prepared, that's what we are seeing. 910 If it was just the mill, it should be zero is what I am saying. 911 MR. MORAN: All right. So if you could just help me understand, then, what these other loads are. We know that we had the F2B line serving the complex. Are there other places that are serving Abitibi that would show up then on a bill that are separate? 912 MR. GARTSHORE: Yeah, we are fed off the rural system on our effluent treatment installation, the 44 kV rural system, and that is approximately a mile -- or a kilometre and a half from the mill, which is billed separately. It is about 3 megawatts. And then there is another portion of our power that we provide for the town of Fort Frances under a long-standing agreement that is delivered through the 8th Street substation directly to the town. I think what we are seeing is those two things showing up on this spreadsheet. 913 MR. MORAN: But if those two things are being delivered separately, how would they register on the relevant meters for the F2B line and the co-gen? 914 MR. GARTSHORE: They shouldn't. I think what has happened is they have taken those into account when they prepared these numbers, because on the surface, it doesn't make sense, it should be a zero. In a month where the complex takes all of its power from the co-gen plant and its own internal hydraulic generation, it should be zero network and zero line connection. And I think this spreadsheet is a little confusing. 915 MR. MORAN: All right. 916 MR. GARTSHORE: But again, I'll come back to the point that in a perfect year, it is about $2 million, and there would be months that there are problems with the co-gen plants that we have to withdraw power from the system, so it would certainly be less than $2 million. 917 So to try to frame the amount in dispute per year, 1.2 million to, say, 1.7 million. And we tried to show it on the spreadsheet, and I don't think we have done it very well, frankly. 918 MR. MORAN: So if there was a need to verify what these numbers should be, the best thing to do would be to go to the IMO and ask them to do that? 919 MR. GARTSHORE: I think so. 920 MR. MORAN: We shouldn't rely necessarily on these numbers. 921 MR. GARTSHORE: I think you can rely on the gross number. 922 MR. MORAN: Yes, presumably the folks on your side can read the bill; right? Because those are set out on the bills you actually received; right? 923 MR. GARTSHORE: Yeah, those are actuals. 924 MR. MORAN: All right. I would just like to end up then, with you, Mr. Snelson. If you were to sketch out the basic case for why the co-gen should be treated as embedded generation, what would you say to the Board? 925 MR. SNELSON: I would say, firstly, that it is the type of co-generation plant that was generally considered would be covered by embedded generation through the transmission system hearing, and that, secondly, it meets the specific definition that is in the Board's rate order of what is an embedded generator, in that it is connected behind the meter that measures the power delivered from the regulated transmission system, and that in considering that, you have to take into account that this is an unregulated transmission system and that the proper definitions of transmission customer and transmission delivery point should be consistent such that the transmission customer is those directly connected, the delivery point is the point of the direct connection. 926 And those are the main points. 927 MR. MORAN: Okay, thank you very much. 928 Mr. Chair, those are all my questions. 929 MR. BETTS: Thank you. We will continue now then with Ms. Aldred's questions, and if you could aim roughly more an appropriate break point in or around or shortly after 3 o'clock, that might work well for a short break. MS. ALDRED: I'll do my best, and if perhaps I don't remember, please remind me. 930 MR. BETTS: Thank you. 931 CROSS-EXAMINATION BY MS. ALDRED: 932 MS. ALDRED: I am going to start out with you, Mr. Gartshore, and move to Mr. Snelson, and I note that Mr. Moran has done a pretty thorough job on some of the questions that I was going to ask on the contract, and so I will attempt to reflect that in my cross-examination. 933 There will be the odd question that I will probably repeat. 934 Mr. Gartshore, I understand that you have been with the Abitibi facility for a long time, since about 1977? 935 MR. GARTSHORE: Yes. 936 MS. ALDRED: And you are obviously familiar with the history of the site and the history of the electricity supply in the area where the site is located. 937 MR. GARTSHORE: Yes, I am. 938 MS. ALDRED: And I understand that the plant, the Abitibi plant was served by Abitibi's own company assets until about 1958; is that correct? 939 MR. GARTSHORE: That's correct. 940 MS. ALDRED: And is it the case that up until 1958, at the time when the plant was served by its own assets, it was actually located in an area that was quite isolated from the rest of the province? 941 MR. GARTSHORE: Yes. 942 MS. ALDRED: And would Abitibi have been one of the few big customers in that area? 943 MR. GARTSHORE: Certainly, probably the biggest in the area. 944 MS. ALDRED: And I understand that in 1958 Ontario Hydro purchased the line that is known as F2B from Abitibi; is that correct? 945 MR. GARTSHORE: Yes. 946 MS. ALDRED: And subsequent to that time, the Abitibi facilities have been supplied with power through the Ontario Hydro grid, and I understand that there were at different times several supply agreements between Ontario Hydro and Abitibi whereby Hydro supplied power for the operation of the plant at Fort Frances; is that correct? 947 MR. GARTSHORE: Yeah, the plant was supplied by its own generation and Ontario Hydro. 948 MS. ALDRED: Right, thank you. And in fact, at tab L of Exhibit 1.1, which is the Abitibi evidence, we'll find reference to a 1968 power agreement and the document located at tab L is actually a 1970 agreement, I believe; is it not? 949 MR. GARTSHORE: Yes, it is. 950 MS. ALDRED: Thank you. And could you please turn to page 1 of that agreement which contains the recitals which set out the context for the agreement. 951 MR. GARTSHORE: Okay. 952 MS. ALDRED: And recital or point 3, which is at the very bottom of page 1 and continues on page 2, reads: 953 "Whereas the company, with the Commission's permission, sells or disposes of part of the power supplied by the Commission pursuant to the 1967 additional power agreement to its affiliate Boise Cascade Corporation for its use in that company's plant at International Falls, Minnesota." 954 And then recital point 4 reads: 955 "Whereas the parties now wish to enter into a separate agreement from the 1967 additional power agreement for a supply of power to the company for resale to its affiliate Boise Cascade Corporation." 956 Would it be fair to say that this agreement that we are looking at now, the 1970 agreement, is essentially an agreement which was facilitating the construction of new transmission facilities in the area of the Abitibi mill and which would allow Abitibi to service increased load at its Ontario facilities; and that it also was agreed that Abitibi could supply its affiliate in Minnesota with power delivered by Ontario Hydro? 957 MR. GARTSHORE: I think the 1970 agreement dealt with replacing the old wooden pole and single-circuit line to the mill with a new double-circuit line. One circuit would feed the Abitibi mill and the other circuit would eventually feed Boise Cascade in Minnesota. 958 MS. ALDRED: And so it provided for the construction of additional facilities by Ontario Hydro, did it not? 959 MR. GARTSHORE: By Ontario Hydro? 960 MS. ALDRED: Or, I'm sorry, it provided for construction for additional facilities to feed the Minnesota load and the Abitibi load in Ontario. 961 MR. GARTSHORE: Yeah, my understanding was the mill was expanding at that point in time with the addition of the Kraft mill in 1972/73, and a rebuild on number 5 paper machine and 1975 on the Fort Frances side and similar things were going on at the Boise Cascade side. There was just a general need to upgrade the line. 962 Prior to that, power flowed down the old circuit through the mill on the 6.9 kV system and across -- we had an export licence to send up 16 megawatts across the border between the two power houses that were there originally when the plant was built in 1912. 963 So what this did was that circuit got to be too small, it was only up to 16 megawatts, so under the new power agreement I believe they can take around 30 megawatts to Minnesota over the new circuit and the new circuit to Fort Frances mill to allow for taking more power as well. 964 MS. ALDRED: And is it the case that those transmission facilities were in fact constructed by Ontario Hydro in accordance with the contract? 965 MR. GARTSHORE: Yes, they were. 966 MS. ALDRED: And are those facilities referred to still in place today? 967 MR. GARTSHORE: The F2B and F3B are still in place today. 968 MS. ALDRED: And we have heard this morning they are still in use today. 969 MR. GARTSHORE: I can't speak to the F3B because that belongs to Hydro One as a backup circuit for Minnesota, but certainly the F2B is in service. 970 MS. ALDRED: And are you also aware that around in 1970, the transmission system in Kenora, Fort Frances and Dryden was reinforced with a 320 kV supply -- a 230 kV supply to service expanding load in the area which would have included the Abitibi site? 971 MR. GARTSHORE: Yes, I am. 972 MS. ALDRED: Mr. Gartshore, I would also like to talk to you about the installation of the Westcoast power generator or NUG, as we have been referring to it today. 973 MR. GARTSHORE: Okay. 974 MS. ALDRED: And I am going to ask you some questions about the contract, the original contract between ICG and Ontario Hydro, and as I said before, I'll try not to replow all the same ground that Mr. Moran has already plowed, but I would like to ask you a few questions. So if you can turn up that contract which is located at tab D of Abitibi's evidence. 975 MR. GARTSHORE: I have it. 976 MS. ALDRED: And if you look at the first page of the contract, I take it you would agree with me that there are two parties to this contract; those parties are Westcoast power's predecessor, ICG, and Ontario Hydro. 977 MR. GARTSHORE: Yes. 978 MS. ALDRED: And so you would agree that Abitibi is not in fact a party to this contract. 979 MR. GARTSHORE: To this one, no. 980 MS. ALDRED: And can we agree that Abitibi did not pay the capital costs for Westcoast power to install the generator? 981 MR. GARTSHORE: Abitibi, no. But if I could add to that: Abitibi, the reason we can buy it for a dollar in 2008 is because we are paying down the capital cost of that plant through our steam purchases. 982 MS. ALDRED: Correct; but you didn't pay the original capital cost. 983 MR. GARTSHORE: The original, no, we did not. 984 MS. ALDRED: And in fact, if you turn to page 2 of the contract, which at the fifth paragraph, it is one of the recitals, so they all begin "whereas", if you count down it is number five, it says: 985 "Whereas ICG has entered into a loan agreement dated as of the 1st day of March, 1989, with Hydro whereby Hydro will lend up to a maximum of $45 million to ICG Ontario to assist in financing the co-generation facility ..." 986 And so I take it this tells us that it was the case that the NUG was in fact financed by Ontario Hydro. 987 MR. GARTSHORE: They received the loan from Ontario Hydro. The total cost of the NUG was in excess of $100 million. 988 MS. ALDRED: And then if we refer to paragraph 3 on the same page, we'll just confirm that the role of Abitibi as it's referred to in this contract seems to have been to purchase the steam produced by the Westcoast power generator. 989 MR. GARTSHORE: What page are you on now? 990 MS. ALDRED: Sorry, I'm on the same page. 991 MR. GARTSHORE: Same page? 992 MS. ALDRED: And it talks about Abitibi's -- at paragraph 3 it talks about Abitibi's ability to purchase steam. 993 MR. GARTSHORE: Yes. 994 MS. ALDRED: Okay. And you would agree with me that this contract therefore does not address a purchase of electricity by Abitibi from Westcoast power but merely a purchase of steam by Abitibi from Westcoast power? 995 MR. GARTSHORE: Correct. 996 MS. ALDRED: And then if you also refer to paragraph 6 again on that same page, it states: 997 "Whereas the parties are willing to enter into an agreement for the supply of power by ICG Ontario to Hydro and by Hydro to ICG upon the conditions herein". 998 And if you would further turn to section 5 on page 8, and this is the section that Mr. Moran went through with us. The first line of the paragraph says: 999 "ICG shall sell and subject to section 5.1 deliver capacity power exclusively to Hydro, which capacity power shall be measured at the metering point." 1000 So what that clause tells us is that the power was being completely sold to Ontario Hydro; is that correct? 1001 MR. GARTSHORE: That's correct. 1002 MS. ALDRED: And a little further down at about line five of the same paragraph it also says: 1003 "Hydro agrees to purchase all capacity power at the metering point." 1004 So we can agree that the transaction here is that all of the power that Westcoast power -- the power that Westcoast power produces is sold to Ontario Hydro and Ontario Hydro buys that power; is that correct? 1005 MR. GARTSHORE: In 1989, that was the only way it could be done, yes, I agree. 1006 MS. ALDRED: And is this contract still in effect? 1007 MR. GARTSHORE: Yes, it is. 1008 MS. ALDRED: So it would be how it is being done right now, too? 1009 MR. GARTSHORE: That's correct, except it is OEFC, as you pointed out. 1010 MS. ALDRED: Right. And Westcoast power rather than ICG, of course. And then, finally, the last two sentences of paragraph 5.1 say: 1011 "Such power delivered to Boise Canada shall be deemed to be delivered at the delivery point, and we explored what that was with Mr. Moran, provided that such capacity power is received by Boise Canada. ICG Ontario shall guarantee that all capacity power measured at the delivery point shall be delivered or deemed to be delivered to Ontario Hydro at the delivery point." 1012 And then you'll recall that if we went back to section 1.11, which I won't take you back to, but that is the definition of the delivery point, it is the same point as selected for the supply of power from Ontario Hydro to ICG and from Ontario Hydro to Boise Canada. 1013 Now, having reviewed all those clauses in the contract, would you agree that what they are telling us is that the ICG -- or Westcoast Power generator is connected only to networks, that ICG is selling its power to Ontario Hydro, Hydro is taking delivery of that power, and then that power is delivered to Boise on behalf of Hydro? 1014 MR. GARTSHORE: You said connected to networks? 1015 MS. ALDRED: Yes. 1016 MR. GARTSHORE: I am not sure what you mean. 1017 MS. ALDRED: Because of the definition of delivery point. 1018 The definition of delivery point is the point at which the -- is the dead-end insulators, so that is the connection into Hydro. 1019 MR. GARTSHORE: Okay. 1020 MS. ALDRED: So doesn't this tell us that the power is being delivered directly to Hydro? 1021 MR. GARTSHORE: Delivered directly to Ontario -- that is the idea, was to deliver directly to Ontario Hydro after the mill load came on. 1022 MS. ALDRED: We have already agreed that the system at the time that the NUG contract was put in -- 1023 MR. GARTSHORE: But if I can go back. 1024 MS. ALDRED: Sure. 1025 MR. GARTSHORE: You said networks, my understanding is the power was being delivered to OEFC. Hydro One got replaced by OEFC. 1026 MS. ALDRED: So it is being delivered directly into the grid, into the power market. 1027 MR. GARTSHORE: To OEFC. 1028 MS. ALDRED: Previously, we talked about the fact that the system was already built up in the area at the time that the NUG was installed, and at the time that the NUG was installed, in fact, the load at Abitibi was being supplied by both the Ontario Hydro network and also, I gather the hydraulic generators were there at that time? 1029 MR. GARTSHORE: Yes, they were. 1030 MS. ALDRED: Okay. So would you agree with me that in fact, at the time that the Westcoast Power generator was installed, it was already possible to supply the Abitibi load without the generator? 1031 MR. GARTSHORE: Yes, it was. 1032 MS. ALDRED: And is it in fact the case that the generator could really have gone elsewhere on the network, it could have been somewhere else other than the Abitibi property itself? It could have been located on the network itself? 1033 MR. GARTSHORE: Well, at the time there was a perceived shortfall for power in the region. Ontario Hydro had recently built a coal-fire plant, Atikokan, there was some discussion about adding a second unit there. 1034 The end result of those discussions, as I said earlier, was the construction of the co-gen plant in Fort Frances and it makes most sense to locate a -- if you are going to make power with gas, it makes most sense to do it with a co-gen in terms of energy efficiency. 1035 MS. ALDRED: So it was a convenient place to put the co-gen, but it did not have to go there? 1036 MR. GARTSHORE: They could have built it anywhere, I suppose, but Hydro was looking for NUGs at the time and it made the most sense in Fort Frances. 1037 MS. ALDRED: And Abitibi would have been able to have been supplied without the generator being located on their property at that time; is that correct? 1038 MR. GARTSHORE: That would be correct, yeah. 1039 MS. ALDRED: Was it not the case that the agreement was therefore drafted in such a way as to ensure that it would be clear that Abitibi would continue to withdraw their demand from F2B? 1040 MR. GARTSHORE: I think it is clear that they tried to -- you know, the reality of the situation is that the power that is generated in the co-gen plant gets used at the mill. So they couldn't sell directly to Boise, so there was terms put in place so that it would look like it was being delivered into the grid, when, in reality, it was just going around on the mill property, so -- 1041 MS. ALDRED: The terms in the contract are trying to make it clear that the power is being delivered into the grid; is that correct? 1042 MR. GARTSHORE: That's what they are trying to notionally display, I guess. 1043 MS. ALDRED: And I think you testified this morning that when the Westcoast Power generation is down, you would expect your supply to come from Hydro One; is that correct? 1044 MR. GARTSHORE: Yes, because we would be connected to the grid, and when we withdraw power from the grid, we should pay. 1045 MS. ALDRED: And your testimony this morning was that the Westcoast Power generator is down for maintenance, is it once or twice a year? 1046 MR. GARTSHORE: I think I said three to four times. Typically, one big maintenance outage, and then perhaps some unplanned ones, and maybe another small outage through the year, so three to four months a year. 1047 MS. ALDRED: So for three to four months a year, you do acknowledge that you are supplied by the Hydro One? 1048 MR. GARTSHORE: For portions of those months, because once you get a peak, it is for the whole month. So in a month where we had a two-week maintenance outage, we would pay like we had drawn power for the whole month in terms of network and line connection. 1049 MS. ALDRED: Is it your understanding that the contract that we just went through between OEFC, or Ontario Hydro at the time, and ICG was structured on the basis that Ontario Hydro would be paying ICG above-average rates for the electricity that it generated? 1050 MR. GARTSHORE: It is my understanding that that would be the case, that they would pay more for NUG power than the going rate at the time. 1051 MS. ALDRED: That would be a reason why Westcoast Power would wish to build the NUG and sell into the grid, because they were getting above-average rates; is that correct? 1052 MR. GARTSHORE: That would be one of the reasons, yes. The other reasons would be steam sales to Fort Frances and at the time they were looking for customers for their gas, for ways to use natural gas. 1053 MS. ALDRED: So the fact that Westcoast Power, and probably other NUGs, would have been receiving above-average rates for the electricity they generated, would you agree that those extra costs would, in fact, be paid by all the customers at the power pool? 1054 MR. GARTSHORE: I would agree, but I would add that they would be paid one way or the other by the customers in the power pool, because if we didn't put a 100 megawatt NUG at Fort Frances there might have been a 200 watt coal-fired generator Atikokan, so ultimately those costs would be split across all the load in Ontario. 1055 MS. ALDRED: But to the extent that they are higher, the power pool would be paying those higher costs? 1056 MR. GARTSHORE: Mm-hmm, and to the extent that any new generation is typically coal or gas, it comes on at a more expensive cost than traditional hydro, so any new generation tends to be higher than average. 1057 MS. ALDRED: And I take it it is the case that since Abitibi, over the years that the NUG has been in place, has been buying from the market, Abitibi will have been paying lower rates than the average rate that the NUG is being paid by OEFC or Ontario Hydro for the electricity that it generated? 1058 MR. GARTSHORE: I would assume so, although I don't have the numbers in front of me, but I would assume so. 1059 MS. ALDRED: So to that extent, Abitibi is benefitting from buying from the market rather than buying from the NUG? 1060 MR. GARTSHORE: I guess to that extent, yes. 1061 MS. ALDRED: And I think you have already agreed to this, but I'll just put it to you one more time, can we agree that the driver behind installing the NUG on the Abitibi site was not because Abitibi needed the supply that couldn't be supplied from the grid already or from its own generators? 1062 MR. GARTSHORE: No, it was built for a number of reasons, one of which was power supply in the area, one of which was a reliable steam supply to the mill. 1063 MS. ALDRED: Just to confirm, Abitibi buys from the IMO-administered market and Westcoast power sells into that market, and there is no contractual relationship between Abitibi and Westcoast power vis-a-vis the purchase of electricity; is that correct? 1064 MR. GARTSHORE: That's correct. 1065 MS. ALDRED: And would you agree with me that had the Westcoast Power generator not been installed, there would be no difference in the contractual procurement of the power for Abitibi; they would still be buying from the market as they are now? 1066 MR. GARTSHORE: Say that again? 1067 MS. ALDRED: If the Westcoast power generator had never been installed, Abitibi would be buying from the market. 1068 MR. GARTSHORE: Yes. 1069 MS. ALDRED: And they are currently buying from the market anyway. 1070 MR. GARTSHORE: Yes. 1071 MS. ALDRED: And is it the case that there has in fact been no change in the physical setup at the Abitibi site, as described in the evidence, since the Westcoast power generator was installed? 1072 MR. GARTSHORE: No material changes, no. 1073 MS. ALDRED: I take it then there was no electrical reconfiguration in response to the order that arose out of the RP-1999-0044 proceeding, which is the proceeding that Mr. Moran explained to you a few minutes ago. 1074 MR. GARTSHORE: None. 1075 MS. ALDRED: Would you like to take your 3 o'clock break? 1076 MR. BETTS: Not if it is going to interrupt your questioning. If you would prefer to keep on that line, we are more than happy to work with you. 1077 MS. ALDRED: I have about three more questions on this particular line, and then I can take a break. 1078 MR. BETTS: Then please proceed. 1079 MS. ALDRED: Do you agree that since Abitibi did not own the generator or pay for its installation, and since we have agreed that there is no shortage of supply in the area at the time, that it is fair to say that the Westcoast power generation was not installed so that Abitibi could self-supply but was installed in order for Westcoast power to sell into the market? 1080 MR. GARTSHORE: I think the original intent was for Westcoast power to sell into the market. But when you read all the agreements together, it is clear that Abitibi was to purchase the plant after 15 years for a dollar, and one of the main contributing factors was Abitibi's purchase of the steam at about $7 million a year demand charges. 1081 So over time, Abitibi basically pays the plant off through steam purchases it gets to buy for a dollar. 1082 So from day one, the intent was for Abitibi to take the co-gen plant for a dollar. It wasn't a matter of we wait for 15 years and then decide whether to buy it or not. It was clear from the outset. 1083 MS. ALDRED: But the NUG would have received the higher prices from OEFC for that entire 15-year period prior to that. 1084 MR. GARTSHORE: That's correct. 1085 MS. ALDRED: And I take it you would agree with me that the transmission assets, which are already in the area and which serve Abitibi when Abitibi is not served by the Westcoast power generator, they need to stay in place. 1086 MR. GARTSHORE: Yes, they do. 1087 MS. ALDRED: Are you really telling the Board that the other 180 transmission customers in the province should pay to maintain those assets which you have acknowledged that both Abitibi and Westcoast do need to remain in place? 1088 MR. GARTSHORE: What I am saying is we'll pay for them when we use power from the grid. It is clear we are connected to the grid; it is clear we don't take power from the grid. And when we do take power, we'll pay; otherwise, we shouldn't have to. 1089 MS. ALDRED: Thank you. 1090 That ends that line of questioning. Thanks. 1091 MR. BETTS: Thank you, Ms. Aldred. 1092 We will then break for, I think judging by the time, let's try to make it a short break. The Board will not object to somebody bringing back a cup of coffee or a cup of tea if they haven't finished it. 1093 So let's aim to be back here in 20 minutes, 20 minutes past 3:00, and we will begin -- or continue with questioning from Ms. Aldred. 1094 We will adjourn at this point. 1095 --- Recess taken at 3:01 p.m. 1096 --- On resuming at 3:20 p.m. 1097 MR. BETTS: Before we resume the questioning from Ms. Aldred, are there any preliminary matters to be dealt with? 1098 If none, Ms. Aldred, please continue. 1099 MS. ALDRED: Thank you. Mr. Gartshore, just to confirm a few more of the contractual matters and then I'll move on. It is my understanding that OEFC pays Westcoast power for the energy that they insert into the market. 1100 MR. GARTSHORE: Yes. 1101 MS. ALDRED: And given the fact that Abitibi buys from the market, does Abitibi not have to be connected to the transmission system to be supplied with their power requirements? 1102 MR. GARTSHORE: No. 1103 MS. ALDRED: Why is that? 1104 MR. GARTSHORE: Because the power comes from the co-gen plant. 1105 MS. ALDRED: Is the line not necessary to be supplied? Westcoast needs the line to get it into the market and you buy from the market. 1106 MR. GARTSHORE: Westcoast needs the line to get the other 25 megawatts out, but the power needs from the mill come from the co-gen plant. 1107 MS. ALDRED: We already agreed, though, you would not want to be I guess disconnected from the grid. You need the grid; is that correct? 1108 MR. GARTSHORE: We are connected to the grid, yes, and we need the grid for when we need to take power. 1109 MS. ALDRED: You settle your power purchases directly with the IMO; is that correct? 1110 MR. GARTSHORE: Yes, we do. 1111 MS. ALDRED: If Westcoast power were to breach its contract with OEFC and fail to deliver power into the market, where would Abitibi get its power? 1112 MR. GARTSHORE: We would have to buy our power from the grid. Say if Westcoast went bankrupt for some reason or ceased to function we would revert to buying power from the grid. The energy would come from the grid. 1113 MS. ALDRED: And given the fact that you have no contract with the Westcoast power company for the delivery of power, I take it you would agree with me that you would have no right to sue Westcoast power for failing to honour its contract with OEFC. 1114 MR. GARTSHORE: With OEFC, but we certainly have issues on the steam supply side, seeing as that's our single source of steam for the mill. 1115 MS. ALDRED: Do you agree with me that if the generator were to be out of service for six months or a year for some reason, Abitibi would still be supplied by the market because Abitibi actually has the right to be supplied by the market? 1116 MR. GARTSHORE: Yes, we would. 1117 MS. ALDRED: Can I please refer you to your evidence at tab 2, page 2 -- I think I mean your witness statement, just bear with me for a minute. I think I might have written the wrong thing down. 1118 No, I'm sorry, I did mean your evidence, so Exhibit 1.1, tab 2, page 2. 1119 MR. GARTSHORE: Okay, I think I am with you. 1120 MS. ALDRED: If you look at paragraph 4, you say that any electricity that is not required for the operations of the complex is conveyed from the complex to the Hydro One transmission system along the Hydro One F2B line. 1121 MR. GARTSHORE: Yes. 1122 MS. ALDRED: And in the preceding paragraph you were talking about the Westcoast power generator. And so I gather in this paragraph 4 you are talking about the electricity that was generated by the Westcoast power generator. 1123 MR. GARTSHORE: Yeah, and the hydraulic plant on the mill site. So any electricity not required for the operations of the complex is conveyed from the complex to Hydro One, so it is the output of the co-gen net the mill's needs going out into the Hydro system. 1124 MS. ALDRED: And so do you agree that the Westcoast power facility uses the Hydro line F2B to sell into the electricity market? 1125 MR. GARTSHORE: Like any other generator, it does, yes. 1126 MS. ALDRED: And I take it that Abitibi relies on line F2B to purchase its energy requirements from the market. 1127 MR. GARTSHORE: When they are not being met by the on-site generation, yes. 1128 MS. ALDRED: So would you agree that both Abitibi and Westcoast power require that line F2B and indeed the network's high voltage transmission system continue to be available to them when they need it? 1129 MR. GARTSHORE: Yes. 1130 MS. ALDRED: And what would follow from that is that those dedicated facilities cannot be decommissioned, because they are needed in order for Westcoast power to fulfill its contractual requirements as well. 1131 MR. GARTSHORE: The F2B line, yes. 1132 MS. ALDRED: In terms of other advantages that Abitibi gains from being connected to the transmission system, do you agree with me that Abitibi also makes use of networks relaying protection, voltage control switching facilities and operating infrastructure to protect the Abitibi load from power system faults and to restore power, either from remote control or locally by trained operating personnel? 1133 MR. GARTSHORE: The same as any other generator in the province, yes, I agree. I would add that the power system in that part of the province is very weak and 100 megawatts of generation represents a strong generating source close to a load, so it adds to the strength of the area, but in terms of what we rely on the system for, it is the same as any other generator. 1134 MS. ALDRED: Would you agree that significant transmission investments have been made over the years both by Abitibi and Ontario Hydro to serve Abitibi's requirement for electrical supply? 1135 MR. GARTSHORE: Yes. 1136 MS. ALDRED: Now, I would just like to ask you a few questions about the physical setup of the site, Mr. Gartshore. 1137 We agree that Abitibi is connected to line F2B. You told me that the average Abitibi load in the normal course of operation is 75 megs; is that correct? 1138 MR. GARTSHORE: Approximately 75 megawatts. 1139 MS. ALDRED: How is the amount of electrical energy purchased by Abitibi from the Ontario electricity market metered? 1140 MR. GARTSHORE: It is metered at our revenue meter on the Hydro One substation on 8th Street, but notionally, it is still being done by taking the difference between what is generated at the co-gen site minus what shows up at the 8th Street, the difference being what the mill used. 1141 MS. ALDRED: In fact, in order to measure the amount of electrical energy which Abitibi purchases from the market, it is necessary to use not one meter but two meters; is that correct? 1142 MR. GARTSHORE: To measure the amount of electricity used in the mill, yes, you have to use two meters. 1143 MS. ALDRED: Can we agree that the amount of electricity used by Abitibi load is not, in fact, measured only at the meter located at the Fort Frances TS? 1144 MR. GARTSHORE: Right. The meter at Fort Frances TS measures the net going into the system. 1145 MS. ALDRED: Where is the meter that relates to the Westcoast Power generator? 1146 MR. GARTSHORE: The revenue meter is at the co-gen site. 1147 MS. ALDRED: Is it on the right-hand side of the diagram there, just beside the generators? 1148 MR. GARTSHORE: Yeah, it is those small green rectangles that says "revenue metering," right at the output of those two generators. 1149 MS. ALDRED: And is the Westcoast Power generator located behind its own meter there? 1150 MR. GARTSHORE: You could say those are the Westcoast revenue meters, yes. 1151 MS. ALDRED: And I take it you agree with me that the 115 kV line on the Abitibi site denoted in red is a line which operates at a transmission voltage? 1152 MR. GARTSHORE: It operates at nominal 115 kV, yes. 1153 MS. ALDRED: And do you, therefore, agree with me that the connection of the Westcoast Power generator is not at a distribution voltage but at a transmission voltage? 1154 MR. GARTSHORE: Well, I'll agree it is connected to the Abitibi Consolidated internal network at 115 kV, yes. 1155 MS. ALDRED: Is it in fact the case that at the time that the NUG was installed for technical and economic reasons related to the size of the Westcoast generator, it was connected at the higher voltage, the 150 kV in order to sell into the market? 1156 MR. GARTSHORE: No. No, it is connected at 115 kV mostly for engineering reasons. It could be connected at 13.8. The output of the generators is 13.8 kV and the largest loads at the GroundWood Mill and the Kraft Mill are 13.8. So, theoretically, it could have been connected at 13.8, which would be below the 50 kV, but for reasons of engineering, for reasons of short circuit capacity, for reasons of cost and the fact that our internal 115 kV system was already at that site, we elected to go at 115 kV. 1157 MS. ALDRED: And the reasons related to cost, am I correct in assuming that if you were to connect in at distribution voltages, there would be significant upgrades and protections that would be required on the system, that there would have been a lot of money that you had to expend in order to do that? 1158 MR. GARTSHORE: It would have been more expensive to do it at 13.8. 1159 MS. ALDRED: Is it in fact possible, although this didn't happen, but is it, in fact, possible that the Westcoast Power generator could have been connected into the Hydro One system through construction of a completely separate transmission line? 1160 MR. GARTSHORE: Yes, it could have, through a completely separate transmission line, yes. 1161 MS. ALDRED: Thank you. I'll just turn to Mr. Snelson now. 1162 Mr. Snelson, we'll just confirm what you have already agreed to, and that is there is hydraulic generation on the Abitibi site and that networks is recognizing that generation as embedded and billing it appropriately? 1163 MR. SNELSON: I understand so, yes. 1164 MS. ALDRED: Is it also the case that Abitibi was paying the charges which are now in dispute when the rates were, in fact, bundled? 1165 MR. SNELSON: That has been agreed to, yes. The bundled rate included a component of transmission, yes. 1166 MS. ALDRED: And when the rates were bundled, was Abitibi in effect net load billed on the hydraulic generation? 1167 MR. SNELSON: Yes, it would have been. 1168 MS. ALDRED: Would you not agree that net load billing was indeed possible in the old scheme before the unbundling, because Abitibi was receiving that on the hydraulic generation? 1169 MR. SNELSON: In the old scheme, it wasn't possible to do something different for energy commodity from what you did for transmission as a service. It wasn't possible to sell or buy energy from somebody without also paying the delivery charge associated with it. 1170 So once the decision had been made that the electrical energy would be sold to Ontario Hydro and not to Boise Cascade, then there was no option in the old scheme but to also pay for transmission. 1171 MS. ALDRED: Boise Cascade was not a party to the contract between OEFC and ICG, was it? 1172 MR. SNELSON: I'm sorry, can you say that again? 1173 MS. ALDRED: I am just confirming that Abitibi was not actually a party to the contract between OEFC and ICG? 1174 MR. SNELSON: I believe you have already confirmed that with Mr. Gartshore, yes. 1175 MS. ALDRED: But Mr. Gartshore, I think, has also testified, and it shows up in the contract, that there were discussions, obviously, with Abitibi at the time so that Abitibi would purchase the steam, and obviously, there would have been discussions, at the time, between Abitibi and the other two parties about locating the generator on the site and other matters like that; is that correct? 1176 MR. SNELSON: I would expect there to have been a three-party discussion between the generator, the load and Ontario Hydro, and that as a result of that, a number of agreements would have been struck as appropriate among the parties to implement their intent. 1177 MS. ALDRED: And would it not have been possible for Abitibi at the time that the NUG was being installed to negotiate, in effect, net load billing for the generator if it wished to at that time? 1178 MR. SNELSON: I don't believe so after the decision had been made that the power -- the electricity commodity would be sold to Ontario Hydro, I don't think Ontario Hydro had any arrangement to sell power without selling transmission. 1179 MS. ALDRED: Didn't we agree that the hydraulic generation was net load billed at the time? 1180 MR. SNELSON: Yes, and in that case, neither the electricity commodity is used within the Abitibi plant, and so Abitibi is not in the position of trying to buy the energy from Ontario Hydro without buying transmission services. 1181 MS. ALDRED: And -- 1182 MR. SNELSON: Having made the decision that the energy would be sold to Ontario Hydro, Abitibi had no option but to buy energy and transmission from Ontario Hydro because there was no way to separate them. 1183 MS. ALDRED: Mr. Moran covered this with you, but I would gather you'll agree that it is fair to say that in order for Abitibi to convince the Board that it should be charged on its net load, net also of the Westcoast Power generation, it is important that the Board be convinced by you that the Westcoast Power generator is embedded? 1184 MR. SNELSON: Yes, that's correct. 1185 MS. ALDRED: And I take it you would agree with me that in order to qualify as an embedded generator, the Westcoast Power generator must meet the definition of embedded generator which is found in the decision with reasons? 1186 MR. SNELSON: And I presume that you are referring to section 3.2.1 of the decision? 1187 MS. ALDRED: That's correct. That's the two-part definition. In your witness statement, you identify a series of three of what you refer to as unusual characteristics of the Westcoast Power facility; is that correct? 1188 MR. SNELSON: That is correct. 1189 MS. ALDRED: And by "unusual", I understand that they are characteristics that one would not normally identify with embedded generation as defined in the decision with reasons; would you agree? 1190 MR. SNELSON: No, I wouldn't agree. 1191 MS. ALDRED: How do you define "unusual"? 1192 MR. SNELSON: They are -- my objection to your statement there is that they would not normally be associated with; right? They are some cases that it is quite normal for those to be associated. For instance, separate ownership is quite normal for embedded generation within a local distribution company, in fact, that's the only way in which it can be within a local distribution company. 1193 Similarly, the change in the revenue requirement or the revenue contribution to transmission revenue and the loss of transmission revenue by recognizing the Westcoast facility as embedded, is common for the NUG contracts that were embedded within distribution companies. 1194 MS. ALDRED: Well, you -- 1195 MR. SNELSON: So these are perhaps unusual for some circumstances. They are unusual for an industrial facility in the separate ownership -- the separate ownership is unusual for an industrial facility. The loss of transmission revenue is unusual for an industrial facility, but it is not unusual for a generator recognized as being an embedded generator, within the meaning of the Board's definition of embedded generation. 1196 MS. ALDRED: But at any rate, I understand that you have identified these three characteristics and you must find -- you must have found that worth addressing with the Board because you spent several -- quite a while this morning going through them one by one. If I could -- 1197 MR. SNELSON: And the reasons I identified them as unusual and felt it was worth spending some time on them is that Hydro One, for instance, has identified the transmission, the connection as possibly being an objection, and the separate ownership as being an objection. So there have been some -- these have been identified by other parties. It is not ones that I invented to talk to the Board about. They were ones that I thought were being raised as controversial issues in this proceeding. 1198 MS. ALDRED: Okay, if I can take you to page 3 of your witness statement, which is Exhibit 1.2. The first characteristic that you identify here is that the facility is connected at transmission voltages. 1199 MR. SNELSON: Yes. 1200 MS. ALDRED: And if we refer to the decision with reasons, it refers to generation which is not connected to the transmission system; correct? 1201 MR. SNELSON: Those are the words that are in there. I believe that what the correct interpretation of those words, and going back to the Hydro One witness statement to the hearing where those words first arose, that that was intended to mean the same thing as being behind the meter, measuring the power delivered from the regulated transmission system. 1202 MS. ALDRED: Can we just concentrate on the definition for a minute. You'll agree it does talk about generation which is not connected to the transmission system; is that right? 1203 MR. SNELSON: Those are the specific words in there, yes. 1204 MS. ALDRED: And at paragraph 1 you stated: "The co-generation facility is connected at transmission voltage within the electricity system that is owned by Abitibi, on the Abitibi property and used to move power around their site." 1205 And then you go on to say in the second sentence of the paragraph, the second paragraph, that: "The connection arrangement at over 50 kilovolts is an accident of history, a matter of technical convenience that does not affect whether the plant is embedded in the industrial customer's facility." 1206 Do you agree with Mr. Gartshore that because of the size of the Westcoast power generator, for engineering reasons and for economic reasons the Westcoast power generator was connected at transmission voltages in order to fulfill its contractual obligations to sell into the grid? 1207 MR. SNELSON: It was connected at transmission voltage for a combination of technical reasons and Mr. Gartshore addressed some of those. He also talked about the 115 kV facilities already being close to that part of their site, which is what I referred to as an accident of history. It just happened to be close to the 115 kV line. 1208 MS. ALDRED: But it was deliberately connected, was it not, into the 115 kV line? 1209 MR. SNELSON: Yes. 1210 MS. ALDRED: The second point that you make about an unusual characteristic is expressed on page 5 of your witness statement, and you refer to the fact that the contractual arrangements are such that recognizing that the co-gen is an embedded generator will effectively cause some loss of revenue. 1211 Would you agree with me that there is no loss in other situations which have been already recognized as embedded generation because the embedded nature of the generation was already accounted for in the calculation of rates? 1212 MR. SNELSON: I don't know exactly what Hydro One included in its calculation of rates, so I am not able to answer that question. 1213 MS. ALDRED: Is it possible that that's the case, that that was already included in the calculation of the rates? 1214 MR. SNELSON: It's possible. I haven't anything to add to that. 1215 MS. ALDRED: And the last aspect of the Abitibi situation which you state is unusual is the fact that the embedded generation is not owned by the load and that statement is at page 4 of your witness statement, that's where you address that issue. 1216 MR. SNELSON: Yes, I actually address it in the second, but I am happy to deal with them in any order. 1217 MS. ALDRED: All right, would you agree with me that there is an important difference between generators which are embedded in LDCs and the Abitibi situation in that in the case of an embedded generator in an LDC, a generation is behind the meter, connected at below 50 kV voltage; they are usually quite small and the savings are passed on to the customers of the LDC? 1218 MR. SNELSON: Can we take those one at a time? 1219 MS. ALDRED: Yes. 1220 MR. SNELSON: And can you just repeat them so I get them one at a time and I'll respond to them one at time. 1221 MS. ALDRED: Certainly. In the case of an embedded generator in an LDC, the generation is behind the meter? 1222 MR. SNELSON: In this case, the generation is behind the meter too. 1223 MS. ALDRED: And it is in an LDC as well? 1224 MR. SNELSON: Yes, they are the same in that respect. 1225 MS. ALDRED: And they are connected in at below 50 kilovolts voltage? 1226 MR. SNELSON: In this case, the Abitibi facility is connected at transmission voltage and the others will be connected at distribution voltage, yes. 1227 MS. ALDRED: And that type of generator is usually quite small. 1228 MR. SNELSON: It would be usually smaller than the 100 megawatts that we have here, yes. 1229 MS. ALDRED: Would they often be a 1 megawatt? 1230 MR. SNELSON: They could be several tens of megawatts. 1231 MS. ALDRED: And the last point was that the savings are passed right on to the customers of the LDC. 1232 MR. SNELSON: I believe that the savings would be passed on to the customers of the LDC through a lower transmission rate in that particular LDC. 1233 MS. ALDRED: Moving on to another point then. In your evidence, you make a distinction between licensed and unlicensed transmission, and you refer to regulation 20/02 and that was handed out this morning. 1234 And I take it you would agree with me that the purpose of this regulation is to relieve certain parties who own transmission assets from the requirement to be licensed under section 57 of the Act. 1235 MR. SNELSON: I believe it relieves them of several sections of the Act. I would have to -- you know, it does relieve them from the need to be licensed, yes. 1236 MS. ALDRED: And I think it also relieves them, for instance, from Section 78 which requires them to get a rate order; is that correct? 1237 MR. SNELSON: That is correct. 1238 MS. ALDRED: Does the regulation exempt a party who owns transmission facilities for which no transmitter's licence is required from paying transmission rates by virtue of being connected to a licensed transmitter by a length of unlicensed transmission line? Does the regulation do that? 1239 MR. SNELSON: Can you repeat that again, please? 1240 MS. ALDRED: Sure. I am asking you whether this regulation allows a party who is connected into the transmission system by a piece of unlicensed transmission, if you will, does it say in this regulation that those people should escape paying rates? 1241 MR. SNELSON: I don't think it says anything about that particular circumstance. 1242 MS. ALDRED: Can you confirm for me that, in essence, Abitibi is relying on the manner in which power flows, physically, at their site to avoid paying the transmission rates? 1243 MR. SNELSON: No, I would say that Abitibi is recognizing that transmission rates and transmission service is based on -- maybe I am agreeing with you, but I want to qualify it. 1244 Definitely, the physical flow is what appears to matter, and one of the things that has to be recognized in the new market paradigm is that energy contracts and how energy is deemed to flow for market purposes can be very different to how energy is deemed to flow for -- how energy actually physically flows on the transmission system. The energy flows on the transmission system are measured with meters and those are physical flows. The energy flows and the energy amounts that are settled for energy contracts can have a whole wide variety of means of settling them. 1245 And the contract with Westcoast Power has become, in the market paradigm, an energy contract. Westcoast Power, or the OEFC, could have a contract -- Westcoast Power could be selling the power to OEFC, or OEFC could have a contract with Abitibi or whoever, to sell the power to whoever they wished to and the transmitter wouldn't be aware of that. 1246 If it was a physical contract for energy, then the IMO would be aware of it. If it was a financial contract for energy, then neither the IMO, nor the transmitter, would be aware of it. 1247 So the contracting arrangements for energy have to be divorced from the physical flows or transmission in the new paradigm. 1248 MS. ALDRED: I think that is a long way of agreeing with me. 1249 MR. SNELSON: I think it may be. 1250 MS. ALDRED: But more simply put, more simply put, the proposition you are putting to the Board is: The power flows on our site in a certain way, and because of that, at certain points we say we are not using the transmission system and when we are not using it, we don't want to pay for it; is that correct? Is that what it boils down to, your case? 1251 MR. SNELSON: No, I think what we are saying there is a meter that measures the power flow that is delivered from regulated transmission system of Hydro One, and that just the same as any other embedded generator, then the charges for transmission should relate to the transmission services that are provided at that point, as measured by that meter. 1252 MS. ALDRED: And I think you said what you are trying to do is to divorce the contractual arrangements from the physical flow; is that correct? 1253 MR. SNELSON: I am not saying I am trying to do that. I am saying that the new market has done that. 1254 MS. ALDRED: Can I refer you to your written statement, your witness statement, page 7. That's where you start to talk about the concept of licenced and unlicenced transmission. 1255 Sorry, it is actually page 9, Mr. Snelson, point 7. 1256 Now, just before I continue, there was a diagram that I believe I sent to your counsel last week which perhaps we could distribute. 1257 MR. MORAN: Mr. Chair, that would become Exhibit 1.7 entitled "Figure 1: Forms of connection to transmission network." 1258 MR. BETTS: Mr. Moran, just to be consistent, can we give the exhibits a pre-fix as well from this point forward, or if it's going to complicate the record, we could leave it this way. 1259 MR. MORAN: I think it will complicate the record, Mr. Chair. 1260 MR. BETTS: Fine, it is 1.7. 1261 EXHIBIT NO. 1.7: FIGURE 1: FORMS OF CONNECTION TO TRANSMISSION NETWORK 1262 MR. MORAN: And more importantly, it might confuse all the lawyers. 1263 MR. BETTS: We can work with it. 1264 MR. SIDLOFSKY: I am sure the engineers will be fine with it, sir. 1265 MR. BETTS: Please proceed, Ms. Aldred. 1266 MS. ALDRED: I am already in trouble because this is a diagram, but hopefully we can get through this. 1267 Did you have a chance to look at this prior to the hearing, Mr. Snelson? 1268 MR. SNELSON: Yes, I did. 1269 MS. ALDRED: Okay. If you could just refer to figure 1, which was sent to you, and if we could look at part A of the diagram which is at the top of the page, I'll just ask you to accept for me that the rectangle in the middle of the box represents the commonly used transmission network system that connects all of the Ontario transmission customers to various generating stations and interconnections. 1270 And this diagram is showing some customers, such as the customer on the left side, load 1, they are shown as connected into the network by licenced transmission, and that would be the bold line that moves from load 1 into the system. 1271 On the right-hand side of the page you'll see that there are other customers that can be connected to the network system by connections owned by a combination of non-licenced transmission owners or licenced transmission owners or a combination of licenced and non-licenced transmission owners. 1272 Would you be familiar with these two types of connection arrangements? 1273 MR. SNELSON: Well, I understand the diagram, yes. 1274 MS. ALDRED: Okay. 1275 MR. SNELSON: The only point of clarification is I am not quite sure what you mean by a combination of licenced and non-licenced. 1276 MS. ALDRED: Well, if you look on the right-hand side of the page, and perhaps I didn't express it very precisely, I think you can see there is a solid line and then a dotted line. 1277 MR. SNELSON: Yes. 1278 MS. ALDRED: The dotted line would represent the line of a non-licenced transmitter and then you'll see that it would be joining up with facilities owned by a licenced transmitter such as Hydro One or GLP or -- 1279 MR. SNELSON: Okay, I understand. 1280 MS. ALDRED: Okay. Would you agree that the mesh network shown in the rectangle serves all of the transmission customers such as load 1 and load 2 that are shown in figure 1(a)? 1281 MR. SNELSON: Yes. 1282 MS. ALDRED: Would you agree that the transmission customer shown in this figure 1(a), whether it is load 1 connected to network system by licenced connections or load 2 that is connected to the network system by a pair of licenced connection and non-licenced connection, all benefit from having a connection to the transmission network that provides them access to the interconnected electricity market in a secure and reliable manner? 1283 MR. SNELSON: Yes. 1284 MS. ALDRED: So in this case, you would agree, would you, that both load 1 and load 2 should pay transmission network service charges on the basis of the network rate approved by the Board? 1285 MR. SNELSON: Yes. 1286 MS. ALDRED: Now, if we can move on to part B of this figure, and this figure we have added in a third party generator, which is on the left-hand side of the page and identified as generator A, and it is also connected to the licenced transmission connection. 1287 Let us assume that this generator is larger than load 1 and it is operating most of the year. In that case, would you agree that load 1 is still benefitting from transmission network and the interconnected transmission market -- electricity market? 1288 MR. SNELSON: Yes, but to a lesser degree, but he would still be liable for the network rate, yes. 1289 MS. ALDRED: Thank you. Now, if you look at part C of figure 1, in this case we have a third-party generator, B, that we have added on the right-hand side of the page, and it is connected but it is connected to non-licenced transmission connection which is dedicated to load 2. 1290 For the combination of load and generation on the left side, let's assume that generator B is larger than load 2 and it is operating most of the time during the year. In that case, can you please tell the Board whether or not load 2 should attract transmission network charges on the basis of its own demand in accordance with the Board-approved transmission rate order? 1291 MR. SNELSON: No, I don't believe it should. I believe, and I don't know what the assumed relationship is between generator B and load 2, but if it is a non-licenced connection, then it is going to be either a short generation connection from a generating plant or it is going to be a facility within an industrial complex. 1292 And given that Hydro One ceases to provide transmission services at the junction between the licenced and non-licenced facilities, then it is an embedded facility. 1293 Now, you can make the same argument that you are making with respect to any embedded generator. If generator A were located within load 1, you could make the same argument. 1294 MS. ALDRED: You think that while load 1 should pay for network service on the basis of its own demand, load 2 does not need to pay for network service on the basis of its own demand? 1295 MR. SNELSON: That is correct, and that is one of the consequences of any decision where you have to draw a line between -- in the middle of gray. 1296 And the decision as to what constitutes embedded generation and what does not constitute generation is quite a fine decision. There are shades of gray on either side, and the Board's rate order has made a call through that gray as to where to draw the line. And generator B -- or load 2, which is supplied in almost -- most of the time from generator B falls on one side of that line, it is an embedded generator. And generator A, which is not within the industrial complex, is connected to a publicly regulated transmission line, falls outside of that definition. 1297 MS. ALDRED: Well, do you not consider that the treatment of load 1 is unfair compared to that for load 2, especially given that both of them benefit from the commonly-used transmission network? 1298 MR. SNELSON: I agree that when you draw a line in a gray area, then there are apparently inequities immediately on either side of that line that you draw, wherever you draw the line. And yes, in this case, in terms of its use of the transmission system, load 1 makes use of the licensed connection between load 1 and generator A, and most of the time that may be the only licensed generation-transmission facilities that it is using. It is using the licensed transmission facilities and it is paying for that, but it is paying standard rates. 1299 MS. ALDRED: Could you now turn over the page to figure 2 that was also distributed earlier. This one is somewhat like figure 1. The rectangle in the middle will still represent the commonly used transmission network, and it too shows that load 1 is connected to the network by licensed connection and load 2 is connected to it by a pair of licensed and non-licensed connection. 1300 Now, can we assume that these two loads represent the total load connected to the transmission network, for simplicity, and let's also assume that the total transmission network revenue requirement is 1.2 million dollars per year. 1301 If we assume that the 100-megawatt load is constant, would you agree that under these circumstances and in accordance with the cost-allocation and rate-design methodology approved by the Board, the network rate would be $1.00 per kilowatt per month? 1302 MR. SNELSON: Can you give me the numbers again? 1303 MS. ALDRED: Yes. The total transmission network revenue requirement is 1.2 million per year. It is a 100-megawatt load, which is constant. And I am asking whether the network rate would be $1.00 per kilowatt per month. 1304 MR. SNELSON: So 100 megawatts times 12 months gives you 1,200 megawatt-months of billing, and you divide that into 1.2 million dollars revenue requirement. You get a rate of $1.00 per megawatt per month -- is it per kiloWatt per month? It is $1.00 per kiloWatt per month. 1305 MS. ALDRED: Thank you. Now, Mr. Snelson, in this case, if I said that on the basis of the transmission rate order approved by the Board both load 1 and load 2 should pay for network service at the rate of 1 dollar per kilowatt per month, would you agree with that? 1306 MR. SNELSON: On the basis of the situation in A in this diagram? 1307 MS. ALDRED: Yes, in A. 1308 MR. SNELSON: Yes. 1309 MS. ALDRED: Now I would like to take you to your evidence at Exhibit 2, tab 2, page 5, which is bullet number 3. 1310 MR. MORAN: Mr. Chair, I wonder if we could confirm if this is Exhibit 1.1 we are looking at. 1311 MS. ALDRED: Yeah, excuse me, it is Exhibit 1.1. It is Exhibit 1.1, tab 2, page 5. Do you have that? 1312 MR. SNELSON: Yes. 1313 MS. ALDRED: And it is stated here that "Abitibi should only pay for transmission service when their production of Westcoast generation and Abitibi's generation is inadequate to meet Abitibi's load requirements." 1314 MR. SNELSON: I'm sorry, I think I may have the wrong exhibit. I was in Exhibit 1.2, and not 1.1. 1315 MS. ALDRED: Okay, I'm sorry, it is your original evidence filing, which is 1.1. 1316 MR. SNELSON: Okay. 1317 MS. ALDRED: It is in tab 2 of that exhibit. 1318 MR. SNELSON: I am not sure I have got the right place. 1319 MR. SIDLOFSKY: Sorry, are you talking about the Abitibi summary of evidence from April 30th? 1320 MS. ALDRED: No, maybe -- do you mind if I just approach your witness and show him? 1321 MR. SIDLOFSKY: Sure. Don't hurt him. 1322 MS. ALDRED: I haven't so far, so ... 1323 MR. BETTS: And can I assume everybody else has that reference before them? Thank you. You don't have to go around and show everybody. 1324 MS. ALDRED: Sorry, that is rather a lot of fuss to read from this paragraph, but there you say: "Abitibi should only pay for transmission service when the production of the Westcoast generation and Abitibi's generation is inadequate to meet Abitibi's load requirements." 1325 Is it true, then, that you believe that Abitibi should be charged for transmission based on the flow of power from Fort Frances TS to the Abitibi complex over line F2B? 1326 MR. SNELSON: Yes. 1327 MS. ALDRED: Okay, if we could just then explore that method of calculating transmission charges by looking now at the situation which is illustrated in if anything 2(b) on the exhibit. 1328 Now, in this figure, this last figure, we have a third-party generator, generator B, which is connected to non-licensed transmission. This generator has an output of 75 megs, and that is 25 larger than load 2. Would you agree that in this case the power flow from the combination of load 2 and generator B will be towards the transmission network B and this power flow will amount to 25 megawatts, if you ignore transmission losses? 1329 MR. SNELSON: I agree. 1330 MS. ALDRED: Now, in this case, should load 2 pay for network service at the same rate, that is, $1.00 per kilowatt per month, on the basis of its demand, that is, 50 megawatts? 1331 MR. SNELSON: Not if generator B is recognized as an embedded generator, and I believe that in this circumstance it probably should be. 1332 MS. ALDRED: If load 2 did not pay for the network service, as you say, would there not be a shortfall of about $600,000 per year in the transmission-network revenue requirement? 1333 MR. SNELSON: There would be a loss of transmission revenue, and I acknowledge that had in my direct evidence. 1334 MS. ALDRED: And who do you think should make up for this difference? 1335 MR. SNELSON: It is a matter that the Board will consider when it next sets Hydro One's revenue requirement and rates. Hydro One may have lost some load from paying transmission revenue as a result of this generator being recognized as an embedded generator. It may have lost some load because of a new embedded generator coming into service and taking advantage of the net load billing that is allowed for in the Board's rate order. 1336 But the Board will also take into account that Hydro One may have received additional sources of transmission revenue and from additional loads that it didn't know of at the time of the rate order. 1337 I mean, we have had -- it is a very hot day today. People are forecasting peak loads this week of 25,000 megawatts. Hydro One's probably got higher loads now than it was expected to have at the time of the rate hearing. 1338 So there are a number of puts and takes that will go into that in that determination of what the rate should be next time the Board considers Hydro One's revenue requirement and re-setting the Hydro One rates. 1339 MS. ALDRED: Well, would you agree with me, though, in the scenario we just discussed, that ultimately, either the transmitters that provide transmission network service would have a shortfall in their revenue or the other customers, such as load 1, will have to pay higher rates compared to the rates they would otherwise have to pay if the power flow methodology were used for calculating transmission charges for this load 2? 1340 MR. SNELSON: I would agree, just the same as it would for any other generator, any other embedded generator that took advantage of the net load billing provided for in the transmission rate order. 1341 MS. ALDRED: Would you then want to use the power flow methodology to determine transmission network charges for all customers, for example, where there is a generator connected to the licenced connection between network and load 1? 1342 MR. SNELSON: I'm sorry? 1343 MS. ALDRED: Would you want to use the power flow concept to determine transmission network charges for all customers even for an example like where there is a generator connected to the licenced connection between network and load 1 in the diagram? 1344 MR. SNELSON: Are you talking about a generator in a similar situation to the generator shown in item C on the previous figure? 1345 MS. ALDRED: Yes. 1346 MR. SNELSON: I would charge load 1 for network services based on the power it takes from the regulated transmission facilities. So it would not net out that particular generator. 1347 MS. ALDRED: Just one last question, Mr. Snelson, we dealt with the matter of licenced and non-licenced transmission, and the considerations of power flow in determining transmission charges. 1348 Would you not agree that these matters could affect a large number of customers and other stakeholders who are not here? 1349 MR. SNELSON: I believe there are relatively few non-licenced transmitters in the province who would have generation connected to them that might be affected by this decision, and so I don't think that this decision would have far-reaching implications for other parties, for many of the parties. 1350 MS. ALDRED: Mr. Snelson, Mr. Sidlofsky -- we are done with these diagrams now. 1351 Mr. Sidlofsky took you this morning through two definitions found in the rate schedule, the April 30th rate schedule, and those definitions were the definitions of delivery point and transmission customer. And you commented on those definitions. 1352 I understood you to say both of those definitions were somewhat unsatisfactory. I think you said, in particular, that the definition of delivery point was not satisfactory, and you suggested some changes; is that correct? 1353 MR. SNELSON: I suggested that in these circumstances the delivery point should be defined as the connection between the licenced and unlicenced facilities. And that's consistent with the historic practice. 1354 MS. ALDRED: And so I gathered when I was listening to your testimony that you thought these definitions were not adequate as they apply to your client's situation? 1355 MR. SNELSON: That is correct, or as Hydro One wishes to apply them to Abitibi's situation, yes. 1356 MS. ALDRED: Now, I take it you agree with your counsel that this hearing is a matter between Hydro One and Abitibi and concerns whether Hydro One is properly applying the rate schedules to the Abitibi situation? 1357 MR. SNELSON: That is correct. 1358 MS. ALDRED: And are you, in fact, suggesting that these definitions which flow out of the 1999-0044 proceeding should be amended in this proceeding in the absence of other parties and stakeholders? 1359 MR. SNELSON: No. 1360 MS. ALDRED: I just have about three more questions. They relate to some interrogatory responses that were given in the related Casco matter, and I'll just hand those out now. 1361 MR. BETTS: I think we have adopted the protocol that we will not give these an exhibit number, but refer to the number of the interrogatory. 1362 MS. ALDRED: Mr. Snelson, I don't really want to get into the specifics of the Casco situation, because that is not what we are here to discuss today, but it is a related matter, and there has been evidence filed with the Board on that, and many of the questions that were asked in the Abitibi matter were also asked in Casco. 1363 If you refer to question 2.6, which is an interrogatory question asked by Hydro One of Casco, the question is: 1364 "Based on the definition of transmission system contained in the OEB Act, please confirm that Cascos..." and it should really be Cardinal's "...115 kV bus and 115 kV transmission line are part of the transmission system." 1365 And then below that we have a response, and I gather that this response was prepared by you? 1366 MR. SNELSON: No, it was not prepared by me, but I did see it before it was sent. 1367 MS. ALDRED: And the response corrects the inaccuracy in the preceding sentence and tells the questioner that they must be talking about the Cardinal line, which is correct. 1368 So it says: 1369 "Casco does not own the 115 kV bus or 115 kV transmission line. Those are Cardinal Power facilities. If this interrogatory pertains to the Cardinal Power transmission line and 115 kV bus..." 1370 So that's a line that is not owned by Hydro One; is that correct, drawing back to the Abitibi case? 1371 MR. SNELSON: The Cardinal Power transmission line is owned by Cardinal Power, I understand. 1372 MS. ALDRED: "Casco understands that these are facilities that convey electricity at above 50 kilovolts, therefore fall within the broad definition of transmission facilities in the Act." 1373 So there is an acceptance that facilities which convey power at above 50 kV fall within the definition of transmission facilities in the Act; is that correct? 1374 MR. SNELSON: And I gave that definition in my direct evidence, yes. 1375 MS. ALDRED: And so you accept that if a transmission facility is rated above 50 kV, it is a transmission facility as defined by the OEB Act? 1376 MR. SNELSON: I said so in my direct evidence, yes. 1377 MS. ALDRED: And then just if you would refer to question 2.7 in the same -- just down one point here, the question is: 1378 "A transmission delivery point is defined in the terms and conditions of the Ontario transmission rate schedules as follows: The transmission delivery point is defined as the transformation station owned by a transmission company or by the transmission customer, which steps down the voltage from above 50 kV to below 50 kV and which connects the customers to the transmission system." 1379 Now, is that the definition of delivery point that you gave here today when you were talking about the Abitibi site? 1380 MR. SNELSON: That is not the definition that I recommended be applied to the Abitibi site, no. 1381 MS. ALDRED: But you acknowledge that the definition in the rates schedule is as pointed out here? 1382 MR. SNELSON: Yes. 1383 MS. ALDRED: And in fact, in your response, you say: 1384 "The step down transformers identified in the interrogatory do step down to Casco and Cardinal as indicated." 1385 Under the stated definition of delivery point, these would appear to be delivery points; is that correct? 1386 MR. SNELSON: That is correct. Can I continue with the rest of the answer? 1387 MS. ALDRED: Certainly. 1388 MR. SNELSON: "However, the definition of transmission delivery point that is quoted is inconsistent, as applied by HONI in this case, with the definition of transmission customer. As detailed in Casco's revised submission dated April 3, 2003, Casco submits it is not a transmission customer of HONI or any other transmitter because it is not directly connected to the transmission system owned by a licensed transmitter in Ontario. No definition of delivery point is required in this case because Casco is not a customer." 1389 MS. ALDRED: Thank you for reading that, but the point of the question was to ask what your definition was of a transmission delivery point, and you confirmed that you understand it to be -- the point at which the voltage is stepped down; is that correct? 1390 MR. SNELSON: That is what is in the transmission rate schedule, yes. 1391 MS. ALDRED: Thank you. Just bear with me for a minute, I'll make sure I don't have any more questions. 1392 MS. ALDRED: Those are my questions, Mr. Chairman, thank you. 1393 MR. BETTS: Thank you very much. 1394 Mr. Sidlofsky, you'll have the opportunity now for redirect, if you have any questions. The Board would prefer to hear your redirect before we ask any questions of clarification, but we will give you the opportunity to redirect following our questions if you find the need to do that. 1395 How long did you anticipate that you might require? 1396 MR. SIDLOFSKY: Sir, I think I only have a few questions. I note that Mr. King had asked for the right to cross-examine witnesses. I think that he may have just intended to cross-examine Hydro One witnesses, but I would think he would go ahead of me if he has any questions. 1397 MR. BETTS: It was my understanding that he was limiting himself to the Hydro One witness panel, but Mr. King? 1398 MR. KING: No, your understanding is correct; it is just the Hydro One panel. 1399 MR. BETTS: Thank you very much. 1400 Mr. Sidlofsky. 1401 MR. SIDLOFSKY: Thank you, Mr. Chair. 1402 RE-EXAMINATION BY MR. SIDLOFSKY: 1403 MR. SIDLOFSKY: Mr. Gartshore, Ms. Aldred asked you whether certain clauses in the power-purchase agreement are telling us that ICG is connected only to Networks; do you recall that question? 1404 MR. GARTSHORE: Yes, I do. 1405 MR. SIDLOFSKY: And that was based on the definition of the delivery point. And I think what you said was that the idea was to deliver it to Ontario Hydro after the mill load came off, and that it was being delivered to OEFC. 1406 I just want to make sure that we are all clear here. When Ms. Aldred is speaking about ICG, that is, the Westcoast power facility, and that is the co-gen facility, being connected only to Networks, there is no physical connection between Westcoast power and Networks; is that right? 1407 MR. GARTSHORE: There is no physical connection. 1408 MR. SIDLOFSKY: And I think you mentioned later on that the terms of the agreement made it look like it was being delivered into the grid notionally, and in fact, it was moving around the complex; is that right? 1409 MR. GARTSHORE: It uses the words "deemed delivered", "to be deemed delivered". 1410 MR. SIDLOFSKY: And Ms. Aldred asked you about whether Abitibi would have been paying lower rates than what was being paid by Ontario Hydro to the NUG under the power-purchase agreement. 1411 MR. GARTSHORE: Yes. 1412 MR. SIDLOFSKY: I think she asked you a couple of questions about a premium being paid to Westcoast for its power. And I think your conclusion, or your answer to her question about whether Abitibi would have been paying lower rates than what was being paid to the NUG was that Abitibi would be paying less than it would be -- than it would have been paying to the NUG directly. 1413 MR. GARTSHORE: Yes. 1414 MR. SIDLOFSKY: Now I believe Mr. Snelson's evidence was that there wasn't a mechanism -- I think it may have been your evidence as well -- there wasn't a mechanism to purchase power directly from the NUG at that point; do you recall that? 1415 MR. GARTSHORE: That's correct. 1989 there was only Ontario Hydro could buy or sell power in the province. There was a monopoly, so only Ontario Hydro could buy or sell power. 1416 MR. SIDLOFSKY: So then as it happened, Ontario Hydro was paying a premium to Westcoast for its power. 1417 MR. GARTSHORE: Yes. 1418 MR. SIDLOFSKY: But is it accurate to suggest that that's the price that you would have been paying to Westcoast if you could have done a deal with Westcoast? Do you know what terms you could have done a deal with Westcoast on? 1419 MR. GARTSHORE: Not really, no. I mean, we would have to look at the price of gas and other things at that time, but it's possible it could have been the same or it is possible it could have been less, but I don't know. 1420 MR. SIDLOFSKY: And of course, you were also buying the steam from Westcoast. 1421 MR. GARTSHORE: That's true, yeah. 1422 MR. SIDLOFSKY: Again for Mr. Gartshore: Ms. Aldred was talking to you about whether you would have to use -- whether Abitibi would have to use two meters to measure the amount of electricity that was being used by the mill. I suppose that would really be three meters, because you have got the two at the co-gen facility and one behind the -- excuse me, one that is at the Hydro One regulated facility; is that right? 1423 MR. GARTSHORE: That's correct. 1424 MR. SIDLOFSKY: Okay. Now, I just want to take you to Section 3.2.1, and I don't need you to turn to it, I'll read it for you. This may be the third or fourth time we have heard this one but: 1425 "Generation that is not connected directly to the transmission system and is behind the meter that registers the electricity supplied from the regulated transmission facilities is referred to as embedded generation." 1426 Now, I'll read that part of that again: 1427 "Behind the meter that registers the electricity supplied from the regulated transmission facilities." 1428 Now, the Westcoast facility is connected to your transmission line. I just want to make sure that we are all clear on this. The meter that registers the electricity supplied from the regulated transmission facilities is where? 1429 MR. GARTSHORE: It is at the 8th Street substation, the top green box on the one-line diagram. 1430 MR. SIDLOFSKY: Now, you do some subtraction between the meters at the co-gen facility and the meters that measure the power -- excuse me, that measure the electricity supplied from the regulated transmission facilities to find out how much your mill has used; is that right? 1431 MR. GARTSHORE: That's correct. 1432 MR. SIDLOFSKY: But is there any question in your mind that the Westcoast facility is behind the meter that registers the electricity supplied from the regulated transmission facility? 1433 MR. GARTSHORE: There is no question in my mind it is behind the meter that registers supply. 1434 MR. SIDLOFSKY: And are the two meters at the co-gen facility relevant to that? 1435 MR. GARTSHORE: No, only the meter at 8th Street. 1436 MR. SIDLOFSKY: Okay. Mr. Snelson, I just want to clarify something. Maybe it is just that I missed the answer, but Ms. Aldred asked you if the Board has to be convinced that the Westcoast facility is embedded in order for Abitibi to obtain net load billing, and your answer to that was yes. 1437 MR. SNELSON: That is correct. 1438 MR. SIDLOFSKY: Okay, the next question was, what I have written down here is, So Westcoast has to meet the definition in Section 3.2.1. Now, I didn't catch your answer on that. I am not sure if you gave an answer on that before Ms. Aldred went into some questions about unusual circumstances. 1439 MR. SNELSON: For the Board to apply its rate order and treat Abitibi as being embedded, then that is the definition of embedded that is in the rate order and I think that Abitibi has to convince you that it meets that definition. 1440 MR. SIDLOFSKY: And is that on the basis of the two-part test that Ms. Aldred has suggested to you? 1441 MR. SNELSON: Well, Ms. Aldred has suggested it is a two-part test. You can read it either way, and my suggestion, my recommendation to the Board, is that it reads it as a one-part test consistent with the way in which Hydro One put it forward to the Board in Hydro One's own evidence. 1442 MR. SIDLOFSKY: And that's really the second part of the sentence, the one I have read ad nauseam to Mr. Gartshore, so I won't read it again. 1443 MR. SNELSON: That's correct. 1444 MR. SIDLOFSKY: All right. Sir, Ms. -- excuse me, Mr. Snelson. Ms. Aldred asked you about the loss of revenue where embedded generation was -- excuse me, where generation was embedded in the LDC systems. I believe that's what she was taking you through. 1445 And her question was whether the loss of revenue wasn't already accounted for in the calculation of Hydro One's rates, Hydro One's transmission rates, and you said you couldn't speak to that. 1446 But I think you went on later to say that new embedded generation would result in revenue loss in any event? 1447 MR. SNELSON: That is correct. 1448 MR. SIDLOFSKY: Okay, so -- 1449 MR. SNELSON: And that was contemplated in the Board's decision. 1450 MR. SIDLOFSKY: And that was contemplated in the Board's decision at -- I am not sure that you specifically referred to a section of the Board's decision. 1451 Could I take you to paragraph 3.2.18, it is at page 29 of the decision, and if you want to use the Abitibi material, that would be at tab 2.E. 1452 MR. SNELSON: What was the paragraph number again? 1453 MR. SIDLOFSKY: Paragraph 3.2.18. It's probably two-thirds of the way down the page on page 29. 1454 MR. SNELSON: I have that. 1455 MR. SIDLOFSKY: Okay. Are you familiar with that part of the decision, sir? 1456 MR. SNELSON: Can I just read that and familiarize myself again? 1457 MR. SIDLOFSKY: Certainly. 1458 MR. SNELSON: This is the paragraph referring to -- it's starting: "However, according to evidence, transmission costs..." et cetera? 1459 MR. SIDLOFSKY: Yes. 1460 MR. SNELSON: Yes. 1461 MR. SIDLOFSKY: And, in particular, a couple of lines down there is a reference to a forecast provided by what is now Hydro One? 1462 MR. SNELSON: Yes, I am familiar with that. 1463 MR. SIDLOFSKY: And would that be the basis on which you are suggesting that the Board contemplated losses in transmission revenue? 1464 MR. SNELSON: That's one of the places that the Board contemplated it, yes, and it contemplated it in the sense of there being new embedded generation, new embedded generation if it is associated with the existing load represents a loss of transmission revenue, and also in this paragraph it refers to a new merchant generation, which would presumably be in LDCs mostly, and that also would represent a loss of transmission revenue to Hydro One. 1465 MR. SIDLOFSKY: And, sir, if I can just take you a few pages along to page 33, paragraph 3.2.33. 1466 MR. SNELSON: Yes. 1467 MR. SIDLOFSKY: Halfway down the page. 1468 MR. SNELSON: I have it. 1469 MR. SIDLOFSKY: That's where the Board makes its determination that net load billing shall apply to network transmission service, and if I could take you to the end there and ask you if that paragraph contains another reference to losses in transmission revenues as a result of its decision? 1470 MR. SNELSON: It does. The last sentence says: 1471 "The Board recognizes that there will be some cost impacts as a result of its findings and that they ought to be mitigated by anticipated developments in new generation." 1472 MR. SIDLOFSKY: And you answered a number of Ms. Aldred's questions with a comment that there would be a loss of revenue, and that would have to be considered when Hydro One goes back to the Minister or back to the Board for rates, I assume; is that right? 1473 MR. SNELSON: That is correct, yes. 1474 MR. SIDLOFSKY: Now, one of Ms. Aldred's questions to you shortly after that was whether the decision here would affect other customers in the province, and I know I am paraphrasing, but I believe that was roughly what the question was. And your answer was that there wouldn't be wide-ranging impacts. 1475 MR. SNELSON: That is correct. 1476 MR. SIDLOFSKY: Is it your understanding that transmission rates are effectively frozen now until 2006? 1477 MR. SNELSON: I believe that's the impact of the Act that was introduced late last year, yes. 1478 MR. SIDLOFSKY: So, sir, as a result -- if Abitibi were eligible for net billing, for net load billing as a result of this proceeding, would there be any immediate rate impact on any other transmission customers in the province? 1479 MR. SNELSON: I don't believe so, unless the Minister were to allow Hydro One to make a rate application to this Board for a change in transmission rates. 1480 MR. SIDLOFSKY: And at that point, there would be a public proceeding, there would be public notice of that application presumably; is that right? 1481 MR. SNELSON: I presume the Board would follow its procedures, yes. 1482 MR. SIDLOFSKY: Sir, those are my questions, thank you. 1483 MR. BETTS: Thank you, Mr. Sidlofsky. 1484 MR. SIDLOFSKY: Sorry, sir, if I could just ask one more? 1485 MR. BETTS: Sure. 1486 MR. SIDLOFSKY: Thank you. 1487 Mr. Snelson, a great deal of the discussion or the questions that Mr. Moran and Ms. Aldred put to Mr. Gartshore had to do with the contractual arrangements for power between Abitibi and Ontario Hydro and between Westcoast and Ontario Hydro. 1488 Do any of those questions and responses relating to the contractual aspects of the electricity supply, have they affected your position on this at all in terms of Abitibi's eligibility for net load billing? 1489 MR. SNELSON: No, they have not. The contract that existed from the time that the NUG first came into service has now become an energy contract between Westcoast and ICG. Energy contracts can have all sorts of flows that are not represented by physical flows. Energy contracts are not revealed to the transmitter, generally. This one is known to the transmitter because it is a pre-existing contract that was on the public record, but it is not normal for energy contracts to be available except between the parties. 1490 A physical contract for energy would be known to the IMO but not to other market participants. A financial contract for energy can be executed without anybody else knowing it. 1491 So in our new paradigm, energy contracts can have all sorts of impacts in terms of notional flows from here to there and back again, but transmission service is to do with the physical flow on the transmission system and what is measured and the way it is dealt with in the rate order, in my mind, anyway, is what is measured as the flow from the transmission system at the point of delivery from the regulated transmission facilities. 1492 And that is independent of whether there is a contractual flow going out from Westcoast Power into the IMO grid and a contractual flow coming back into Abitibi, because Abitibi might have a contract with somebody else for the supply of energy or it might just take its energy from the IMO market on a spot basis. 1493 So energy contracts can be going in and out at the same time, and netting one way or another, and they have nothing to do with the physical flow of transmission, per se; it is the net effect of all of the contracts and all of the flows on the transmission system that affect the power delivered from the transmission system to transmission customers, and that is the basis of transmission rates. 1494 MR. SIDLOFSKY: Now those are my questions, thank you, sir. 1495 MR. BETTS: Thank you. 1496 The Board has a few questions. 1497 Mr. Smith. 1498 QUESTIONS FROM THE BOARD: 1499 MR. SMITH: Mr. Snelson, you said I think going back to the original deal, which I know you weren't a part of when this co-gen facility was created and the contracts were signed with Ontario Hydro as it was then, I think on two occasions you said that the decision was made at the time to sell the power to Hydro rather than to Boise Canada. 1500 Mr. Gartshore said a couple of times in his testimony, at least I interpreted him saying that Hydro had to be involved in this deal at the time and that there was no -- I don't want to put words in his mouth, but there was no choice but to sell the power to them. 1501 Could you or Mr. Gartshore review for me what were the options at the time, and if there was a decision to sell to Hydro rather than Boise, why was that taken, if it resulted in gross load billing and maybe other things? 1502 MR. SNELSON: I guess it is a legal question as to what could or could not be done at the time, but my layman's understanding of it is that Ontario Hydro had certain monopoly powers at that time under the Power Corporation Act, and somebody would have to confirm that from a legal point of view, and that it would probably have required the approval of Ontario Hydro if Abitibi had wanted to buy power from Westcoast or ICG directly rather than from Ontario Hydro. 1503 So I suspect that would have been a requirement that Ontario Hydro would have had to waive its right to exercise its monopoly power, but one of the lawyers can do that better than I can. 1504 MR. SMITH: All right. Your word "a decision was made" is what threw me, that there was another option they could have immediately gone to. 1505 I have one other question for you, Mr. Snelson. Going back to the paragraph 0044, 3.2.1, that we have referred to a great many times. If you could just clarify for me: You talk about your interpretation and what you think is Hydro One's interpretation of a one-part test or a two-part test. 1506 MR. SNELSON: Yes. 1507 MR. SMITH: And I am confused as to what a one-part test is and what a two-part test is. 1508 MR. SNELSON: Okay. The paragraph we are all referring to is 3.2.1. 1509 MR. SMITH: Yes. 1510 MR. SNELSON: And the words that are in there are: "Generation that is not connected to the transmission system", and that is a test, that is a criterion, according to Hydro One. 1511 MR. SMITH: Right. 1512 MR. SNELSON: "... and is located behind the meter that registers the electricity supply from the regulated transmission facilities." 1513 That appears to be, from the form of the words, a second test. 1514 MR. SMITH: Right. 1515 MR. SNELSON: It has to be both not connected to transmission and behind the regulated transmission facility -- behind the meter showing the power flow from the regulated transmission facility. 1516 That is what I mean by saying that it is -- the form of words appears to be a two-part test and that is what Hydro One is relying upon, because Hydro One maintains that the generation at Westcoast power is connected to the transmission system. They say it is connected to the provincial transmission system; okay? And whether or not it is behind the regulated meter doesn't matter; okay? 1517 Now, the point that we have made is that in the Hydro One evidence to that proceeding, it is very clear that Hydro One intended to use essentially the same definition, but they defined it as a one-part test. They said that generation that is not connected to the transmission system is embedded generation. For the purposes of this proceeding, that is generation that is behind the meter that measures the power generated for the regulated transmission. 1518 So the definition they put in their own evidence makes it clear they intended it to be a single-part definition at that time. 1519 MR. SMITH: The single part being "behind the meter"? 1520 MR. SNELSON: "Behind the meter" being the single most clear, yes. 1521 MR. BETTS: I have just one request and perhaps for an undertaking, if it is possible, and then one question. 1522 With respect to Exhibit 1.5, which is the chart, certainly it is a very useful chart except that now there has been some question raised about its accuracy. I think I am correct in saying that. 1523 Is it possible that this chart could be revised so that the inaccuracies -- I appreciate that it is still based on estimates, but that the estimates become more precise? 1524 MR. GARTSHORE: Yes, I think we could revise that and do a much better job and present a much clearer picture than what is there. 1525 MR. BETTS: Thank you, then perhaps we'll establish an undertaking for that. 1526 MR. MORAN: Mr. Chair, that would be Undertaking U.1.3. Just as a question of clarification, Mr. Chair, there was a discussion of inaccuracies and I think Mr. Gartshore indicated that the IMO would be the best source of information. Are you proposing that the information be obtained through the IMO to update the -- 1527 MR. BETTS: Not necessarily. I am looking for a more accurate assessment -- if Abitibi is uncomfortable with doing it themselves, then that would be the only recourse, but I am still only looking for an estimate, but with the obvious errors eliminated. 1528 MR. MORAN: All right, so Undertaking U.1.3, an undertaking to review Exhibit 1.5 and to update it, removing inaccuracies. 1529 UNDERTAKING NO. U.1.3: TO REVIEW EXHIBIT 1.5 AND TO UPDATE IT, REMOVING INACCURACIES 1530 MR. BETTS: Thank you. 1531 The other question that I had relates to the contributions to the transmission line. I think it is F2B, if I have understood what is going on here, and Abitibi's original involvement and then whether there was compensation and so on. 1532 And I wonder, Mr. Gartshore, could you take me through that once more as to how that happened? 1533 MR. GARTSHORE: Okay. My understanding is that the initial line needed to be replaced. The initial line was the old company line that was built in the '20s. 1534 So when the '70s came, the mill was going to expand, the Fort Frances mill was going to expand and needed more power. The mill across the river at International Falls, Minnesota, also was in a situation where they were taking power from Hydro One for quite a period of years. 1535 So a deal was struck to build a new twin-circuit line from 8th Street to the Fort Frances mill. One side of the line, one circuit was called the F2B. The other side was called the F3M and that continued on across over to Minnesota. 1536 The company, Abitibi -- the Abitibi of the day agreed to pay for the line in installments. The line was built, so we are assuming that the installments were paid. The deal clearly spells out that if power is taken over that line from a certain length of time after the commencement date, the money that Abitibi paid would have been refunded. 1537 We know that power was not taken during -- before the commencement date, or in the period of time after the commencement date that we had the window to take power on. It was not taken for at least a year after that because the project was delayed. 1538 So we have no record of being reimbursed for our installment payments which covered the full cost of the line. 1539 So we are of the opinion that we paid the full cost of the asset. The F2B is essentially untouched since 1970. The F3M did have some work done on it, but that line has nothing to do with the F2B. It is the line that goes to Minnesota. 1540 So just to sum it up, we are of the opinion that we completely paid for that line, but we all recognize it was 34 years ago. It is hard to find the exact records of payments. But the line is there and was built, so somebody had to pay for it and we do take power away. 1541 But failing that, just treat us like any other embedded generator in the province. 1542 MR. BETTS: So I think I understood it correctly that you are unable to provide any evidence that in fact your predecessor paid for any portion of that line. Did I understand that you said the agreement indicated they should, but you have assumed from there that they did? 1543 MR. GARTSHORE: That's correct. 1544 MR. BETTS: So you are not certain that you did. 1545 MR. GARTSHORE: Yeah. 1546 MR. BETTS: And you are also unable to provide any evidence that there was any compensation. You have no records that would support that one way or the other? 1547 MR. GARTSHORE: We have no records. 1548 MR. BETTS: Okay, thank you, I just wanted to clarify that. 1549 The Board Panel has no further questions. 1550 Mr. Sidlofsky, do you feel you need to redirect based on our questions? 1551 MR. SIDLOFSKY: No, I think I am satisfied with my re-examination. There are only so many times I can read section 3.2.1 of the decisions. 1552 MR. BETTS: Okay, thank you. 1553 It looks like we have reached, then, the end of the day. I am going to thank this panel right now for their participation and you have aided us in this process and we still have information to take in. 1554 It appears that we will be receiving evidence from Hydro One Networks' witness panel tomorrow morning. 1555 The Board still has a requirement to deal with this matter tomorrow, in that there are other hearings lining up behind us and in fact we will lose some of our panel if we don't deal with it tomorrow. 1556 So we encourage everybody to keep that very rigid time line in mind. 1557 Unfortunately, we considered moving the starting time earlier tomorrow to see if that would help us at all, but that's impossible because of a pre-scheduled matter for the Board. 1558 So we will be convening tomorrow morning at 9:30 as scheduled, and unless there are any questions, I think we are ready to adjourn. 1559 Anything for the Board at this point? 1560 We will adjourn now until 9:30 tomorrow morning. Thank you all. 1561 --- Whereupon the hearing adjourned at 4:48 p.m.