1 1 RP-1999-0044 2 3 4 IN THE MATTER OF the Ontario Energy Board Act, 5 1998; 6 7 8 AND IN THE MATTER OF an Application by Ontario 9 Hydro Networks Company Inc., for an Order or 10 Orders approving year 2000 transmission cost 11 allocation and rate design. 12 13 14 Hearing held at: 15 2300 Yonge Street, 25th Floor, Hearing Room No. 1, 16 Toronto, Ontario on Friday, November 19, 1999, 17 commencing at 0930 18 19 20 21 22 23 TECHNICAL CONFERENCE 24 25 VOLUME 1 26 27 28 2 1 APPEARANCES 2 HAROLD THIESSEN/ Board counsel, Board 3 KATHI LITT/ staff 4 COLIN SCHUCH/ 5 NABIH MIKHAIL 6 RICHARD STEPHENSON Power Workers' Union 7 ALAN MARK/ Municipal Electric 8 KELLY FRIEDMAN Association 9 RICK COBURN Inco Limited 10 ZIYAAD MIA Ottawa Hydro and Coalition 11 of Distribution Utilities 12 JULIE GIRVAN Consumers' Association of 13 Canada 14 BRUCE CAMPBELL/ Ontario Power Generation 15 JOHN RATTRAY/ Inc. 16 JOEL SINGER 17 MARK RODGER Toronto Hydro Electric 18 System Limited 19 JAMES FISHER Association of Major Power 20 Consumers in Ontario 21 KEN SMELSON/ MPCO 22 JIM FISHER 23 MIKE McEACHEN Imperial Oil 24 PETER BUDD/ TransAlta Energy Corporation 25 ADAM WHITE 26 ROGER WHITE ECMI 27 28 3 1 APPEARANCES (continued) 2 3 ED ROBERTSON VECC 4 DAVID DRINKWALTER/ First Nations 5 CAROL GODBY 6 ERIK GOLDSILVER Five nations Energy Inc. and 7 Electrical Contractors 8 Association of Ontario 9 BOB FAGAN IPSO, Independent Power 10 Producers Society of Ontario 11 JEAN-FRAN€OIS MONDU Marketing d'‚nergie, 12 Hydro-Qu‚bec 13 PETER McBRIDE Ontario Mining Association 14 TOM ADAMS Energy Probe 15 KEN LIDDON Suncor Energy Inc. 16 JOHN McGEE FOCA 17 BRUCE ANDER/ Tormont Energy 18 JAMES SMALL 19 GAYE-DONNA YOUNG Markham Hydroelectric 20 Commission 21 NANCY WOOD Five Nations Energy 22 CAROL SMITH British Energy 23 RICHARD BATTISTA Union Gas Limited 24 DONALD ROGERS/ Ontario Hydro Networks 25 BRIAN BOYCE Company 26 27 28 4 1 Toronto, Ontario 2 --- Upon commencing Friday, November 19, 1999 3 at 0930 4 MR. THIESSEN: Good morning and 5 welcome to the Ontario Hydro Networks Company technical 6 conference for the RP-1999-0044 proceeding. 7 My name is Harold Thiessen and I am 8 with Board staff. 9 For the record, Ontario Hydro 10 Networks Company, or OHNC, has applied for an order or 11 orders approving a cost allocation and rate design 12 proposal for rates for the transmission of electricity 13 that would be effective upon the declaration of open 14 access by the government of Ontario currently planned 15 for November 2000. 16 The Board has assigned file number 17 RP-1999-0044 to this case. 18 The rates which are proposed in this 19 application are designed to recover the revenue 20 requirement approved by the Board for the year 2000 in 21 a transitional rate order RP-1998-0001 issued on April 22 1, 1999. 23 The purpose of today's conference is 24 for intervenors and Board staff to seek clarification 25 of the profiled evidence of OHNC and to increase 26 intervenor and Board staff understanding of the 27 evidence. 28 As this conference is schedule for 5 1 only one day, I would ask that all participants use 2 this session for information gathering and 3 clarification only and refrain from aggressive 4 cross-examination, presentation of positions, or 5 argument. 6 I would ask intervenors to keep in 7 mind that, if an OHNC witness is not able to answer a 8 question fully, or if the information requested is not 9 readily available today, a formal request for this 10 information can always be made through the 11 interrogatory process. 12 There will be a transcript prepared 13 for the proceeding today and it will be forward to all 14 intervenors in the coming week. The transcript will 15 form part of the record of the proceeding and is 16 commonly adopted by the witnesses either when they 17 testify during the oral hearing or by affidavit. 18 I believe that OHNC has prepared and 19 circulated an agenda for today, which identifies the 20 order in which various sections of the evidence will be 21 discussed. 22 In terms of the order of questioning, 23 my suggestion is that Board staff lead off on each of 24 the evidence sections, followed by intervenors in order 25 of appearance. 26 Barring any objections, we will be 27 providing a live feed of this conference to the 24th, 28 25th and 26th floors of this building to allow other 6 1 Board staff and members of the Board an opportunity to 2 monitor the proceeding. 3 I would suggest that we commence in a 4 few moments, and continue until a 15-minute break, 5 which will take place at about 10:45. Then we can 6 reconvene until the lunch break, which will take place 7 at or around 12:30 for one hour. 8 I would also like to remind everyone 9 of the upcoming events as set out in procedural order 10 No. 1 for this proceeding. 11 On Wednesday of next week, November 12 24th, an issues conference will take place here at the 13 Board's meeting room at 9:30 a.m. The purpose of this 14 issues conference is to discuss the draft issues list 15 proposed by OHNC, which was attached as Exhibit A to 16 the procedural order. 17 The day will be devoted to determine 18 a proposed issues list for consideration by the Board. 19 If additional time is required for the issues 20 conference, November 25th has been set aside. 21 The Board will consider the proposed 22 issues list on Friday, November 26, 1999 at 9:00 a.m. 23 at what is commonly called Issues Day. 24 Those are my introductory remarks. I 25 think that at this point we could have appearances. 26 Please introduce yourselves and state your name clearly 27 and spell it for the court reporter and state your 28 affiliation. 7 1 I think we will begin with Board 2 staff. 3 MS LITT: Kathi Litt. 4 MR. SCHUCH: Colin Schuch. 5 MR. MIKHAIL: Nabi Mikhail, Board 6 staff. 7 MR. STEPHENSON: Richard Stephenson. 8 I am counsel for the Power Workers' Union. 9 MR. MARK: Allan Mark, counsel for 10 the Municipal Electric Association. With me is Ms 11 Kelly Friedman. 12 MR. COBURN: Rick Coburn. I am 13 counsel for Inco Limited. 14 MR. MIA: Ziyaad Mia. I am appearing 15 on behalf of a group of so-called distribution 16 companies listed in the intervenors' list with one 17 amendment: It doesn't include Bracebridge Hydro any 18 longer, and I am also appearing on behalf of Ottawa 19 Hydro. 20 MR. CAMPBELL: Bruce Campbell, 21 appearing for Ontario Power Generation Inc. Also 22 appearing for OPG is Mr. John Rattray, and assisting us 23 today in these proceedings is Joel Singer, of Awad and 24 Singer. 25 MR. RODGER: Mark Rodger, appearing 26 as counsel to Toronto Hydro Electric System Limited. 27 MR. FISHER: James Fisher, counsel to 28 the Association of Major Power Consumers in Ontario. 8 1 MR. SMELSON: Ken Snelson, assisting 2 Jim Fisher for AMPCO. 3 MS GIRVIN: Julie Girvin for the 4 Consumers Association of Canada. 5 MR. McEACHEN: Mike McEachen, for 6 Imperial Oil. 7 MR. BUDD: Good morning. Peter Budd 8 on behalf of TransAlta Energy Corporation. With me is 9 Adam White. 10 MR. WHITE: Roger White, with ECMI, 11 representing a number of municipal electric utilities. 12 MR. ROBERTSON: Ed Robertson for 13 VECC. 14 MR. DRINKWALTER: David Drinkwalter, 15 appearing with Carol Godby, who I expect to be here 16 shortly, on behalf of the First Nations. 17 MR. GOLDSILVER: Erik Goldsilver, 18 counsel to the Five Nations Energy Inc. and the 19 Electrical Contractors Association of Ontario. 20 MR. FAGAN: Bob Fagan, from TCA, here 21 on behalf of IPSO, Independent Power Producers Society 22 of Ontario. 23 MR. MONDOU: Jean-Fran‡ois Mondou, on 24 behalf of Marketing d'Energie, Hydro-Qu‚bec. 25 MR. McBRIDE: Peter McBride, Ontario 26 Mining Association. 27 MR. ADAMS: Tom Adams on behalf of 28 Energy Probe. 9 1 MR. LIDDON: Ken Liddon, appearing 2 for Suncor Energy Inc. 3 MR. McGEE: John McGee, representing 4 FOCA. 5 MR. ANDER: Bruce Ander, for Tormont 6 Energy and with me is James Small. 7 MS YOUNG: Gaye-Donna Young, on behalf 8 of Markham Hydroelectric Commission. 9 MS WOOD: Nancy Wood on behalf of 10 Five Nations Energy. 11 MS SMITH: Carol Smith, British 12 Energy. 13 MR. BATTISTA: Richard Battista, 14 Union Gas Limited. 15 MR. THIESSEN: Thank you. Is that 16 everyone? 17 Before I turn the proceeding over to 18 OHNC, is everyone clear on today's proceeding?Are there 19 any questions or procedural matters that anyone would 20 like to ask at this point? 21 If not, then I will turn the matters 22 over to OHNC. I believe they will have some 23 introductory remarks and then the witness panel will be 24 available for questions. 25 MR. ROGERS: Thank you very much. My 26 name is Donald Rogers and I am counsel to the Ontario 27 Hydro Networks Company. 28 With me is Brian Boyce, advisor for 10 1 the Regulatory Affairs department of the company and 2 the two witnesses today will be David Curtis to my 3 right and Andrew Poray to his right. 4 Mr. Curtis is the manager of 5 Transmission Regulation for the applicant and Mr. Poray 6 is manager of Pricing and Product Development and I 7 think a lot of you will know them. 8 This is a little bit unique in terms 9 of technical conferences because of the extensive 10 stakeholder process that has taken place, but we are 11 having a technical conference today. 12 Many of you are very informed about 13 the issues, I know, from the stakeholder conferencing 14 that went on. 15 Today is a day for the applicant to 16 try and answer your questions of a technical nature 17 which are not appropriate to raise in a hearing because 18 they are so technical and we will do our best to answer 19 those questions for you in the hope that we can cut 20 down in unnecessary hearing time and also reduce 21 interrogatories, hopefully. 22 It is not a day for legal arguments 23 and, hopefully, I won't have much to say today. I can 24 sit back and learn with the rest of you. What we would 25 like to do is to introduce our two witnesses, have them 26 give you a very brief overview of the application, 27 address a couple of areas which we know are a concern 28 to some of you right the top, and then answer questions 11 1 for the balance of the day. 2 So what I would like to do is to turn 3 this over now to David Curtis and Andrew Poray, and I 4 think, David, you have some opening remarks and then 5 Mr. Poray will give us some information about cost 6 allocation and the questions on cost allocation will be 7 directed to Mr. Poray, I believe. Is that right? 8 MR. CURTIS: Yes. 9 MR. ROGERS: Okay. 10 MR. CURTIS: Good morning. We have a 11 brief presentation to make to you that gives an 12 overview of our application and, hopefully, the hard 13 copy handouts have already been made available to you. 14 We will provide an overview of the 15 application. I would like to cover the stakeholder 16 consultation process that we went through. Andy will 17 cover the cost allocation and the rate design, and also 18 the updates and changes to the application will be 19 introduced. 20 OHNC engaged in a very extensive 21 stakeholder consultation process earlier this year. It 22 was predicated on providing a continuous opportunity to 23 dialogue in terms of supporting the development of this 24 particular application. 25 We began after the Board made its 26 ruling at the 1st of April with a series of small group 27 meetings that took place through April and May. 28 Through this period we also developed 12 1 our plan and program for stakeholder consultation, and 2 in particular developed a research program based on 3 Canadian Standards Q850 process for stakeholder 4 consultation. 5 On July the 26th, we conducted our 6 first stakeholder workshop. This provided an early 7 opportunity for stakeholders to get together to talk 8 amongst themselves as well as to talk with us to gain 9 insight into the various issues that pertain to this 10 particular proceeding, and an opportunity to ask for 11 any technical clarification. 12 In this first meeting, stakeholders 13 came together and decided that net versus gross load 14 was one of the main issues of this proceeding and an 15 advisory team was struck to examine this particular 16 issue. 17 In August, in the middle of August, 18 we conducted two technical sessions, again to provide 19 stakeholders with opportunities to come forward and 20 discuss with us any technical matters that they had, 21 seek any technical clarification. 22 On August the 26th, we conducted a 23 technical teleconference as well. This was to provide 24 stakeholders with an opportunity to gain further 25 technical understanding or technical clarification 26 around the options that we had put forward at that 27 time. 28 On August 30th, we conducted a 13 1 stakeholder forum, which again provided stakeholders 2 with an opportunity to come together and discuss the 3 various issues, and to seek any technical clarification 4 that they required. 5 Also at this meeting it was decided 6 that the advisory team should continue on and to look 7 at the broader issues that had been identified in the 8 course of the development of this proceeding. 9 Through the month of August, we also 10 conducted a series of roundtable sessions with the 11 First Nations groups. We travelled to six different 12 locations in Ontario and provided again the opportunity 13 of information and dialogue between ourselves and the 14 First Nations groups and the opportunity to seek any 15 technical clarification. 16 Throughout this whole process, we 17 offered other avenues, other channels for stakeholders 18 to communicate with us, and to ask any technical 19 questions that they may have had. This, for example, 20 was through avenues such as fax, e-mail and telephone 21 conversations with individuals within OHSC. 22 I would like now to turn the rest of 23 the presentation over to Andy, and as I said he will go 24 through the cost allocation and the rates as well. 25 MR. PORAY: Good morning, ladies and 26 gentlemen. 27 What I wold like to do is just 28 briefly take you through the rest of the application 14 1 concerning cost allocation and rate design -- can 2 everybody see this all right? 3 In essence what we want to do is to 4 allocate the costs so that they are done in a fair and 5 equitable manner and determine the full requirement for 6 developing the rates. So we identified the principles 7 by which we would allocate the costs. We did an 8 assessment of the options, the types of cost allocation 9 options that we considered, whether it would be a 10 single pool, or multiple pools, or whether it would be 11 location- specific. 12 MR. THIESSEN: Excuse me for 13 interrupting. I think people at the back are having a 14 little difficult hearing. If you could move the 15 microphone a bit closer. 16 MR. PORAY: All right. We then went 17 through a process of identification of the assets that 18 are store in the Asset Registry of Ontario Hydro 19 Networks Company and the associated costs. We then 20 tried to determine the functionalization of the assets 21 and the connectivity of the assets -- which customers 22 were connected to what assets and which delivery 23 points. 24 And then we went through a process 25 that identified the direct assignment of costs to the 26 specific functions and pools and those costs which 27 couldn't be directly assigned would then have to be 28 allocated and we derived the allocators to do so and 15 1 then we assigned the allocation of the revenue 2 requirements to the specific functions and pools. 3 The actual rate design process 4 consisted of a number of elements which we reviewed 5 with stakeholders throughout the process, point of 6 billing, the transmission and distribution boundary or 7 whether it should be down at the customer level, the 8 retail level, the definition of who is the transmission 9 customer, what are the charge determinants and we 10 derived a variety of options to address the number that 11 we could examine. 12 And then the issue of net load 13 billing versus gross load billing. Exporting 14 wheel-through transactions, this will be the charging 15 for those entities that wish to export or to use the 16 transmission system to cross from one jurisdiction to 17 another. 18 We looked at the treatment of new 19 connection investments. We then addressed should 20 generators pay for existing transmission. We then 21 looked at locational transmission pricing, which is the 22 specificity of costing. We tried to adjust the 23 treatment of existing Ontario Hydro contracts. These 24 are contracts that are in existence between Ontario 25 Hydro customers and the former Ontario Hydro and the 26 treatment of low voltage shared facilities. 27 We then developed the rate schedule 28 and the conditions of service and addressed some 16 1 aspects of implementation of the transmission service 2 and transmission rates. 3 I would like to touch on three 4 elements of our submissions which were dealt with 5 fairly late in the stakeholder consultation process and 6 in the development of our submission. 7 The first one deals with the rate 8 design, the charge determined and symmetric under 9 option that in fact we went forward with. That is that 10 the network service will be charged on the basis of a 11 dollar per kilowatt for customer demand that is the 12 higher of the customer's non-coincident peak demand or 13 85 per cent of the customer's -- I'm sorry the 14 customer's monthly coincident feed demand or 85 per 15 cent of the customer's peak demand during the peak 16 period between the hours of seven a.m. to seven p.m. 17 during a working day. 18 We felt that this approach for 19 charging the network represents a balance of cost for 20 value to fairness and customer choice. I think we felt 21 that this represented a general acceptance by 22 stakeholders, recognizing the fact that the 23 transmission system as a whole sees a blend of demands, 24 not just a single non-coincidental sum of non-constant 25 peak, but rather a blend or a diversity of peak demands 26 that really combine customer usage from the customers 27 spread throughout the transmission system. The use of 28 the higher of, it really is to mitigate the potential 17 1 for free ridership by customers. 2 The other element pertains to the 3 treatment of existing contracts and our submission puts 4 forward the recommendation that all customers who had 5 these contracts with Ontario Hydro should be treated in 6 no different manner than customers who didn't have 7 those contracts. Essentially, all transmission 8 customers should be treated on the same basis. We 9 believe that this is the right way to go forward in the 10 unbundled environment. 11 Finally, an element dealing with the 12 export and wheel-through, but there will be a charge 13 for using the transmission to export and wheel-through 14 in addition to the charges which the IMO will impose as 15 a result of redispatching the system if it's necessary 16 to cover incremental costs and congestion. This charge 17 will be included in the IMO settlement process and 18 there will be some reduction of this charge based on 19 calculations involving any surplus that might exist in 20 the accounts that's held by the IMO tracking the 21 auction of the transmission rights. 22 For those generators and for those 23 entities who have purchased transmission rights, we 24 would use that information to calculate a reduction in 25 the charges that were used for the export and wheeling. 26 In essence, this is to respond to a 27 feeling from most stakeholders that there should be 28 some transaction charges to contribute to the cost of 18 1 the transmission infrastructure. The fee that we are 2 proposing to charge is quite comparable to the charges 3 imposed by other jurisdictions around us. 4 What I would like to do is to close 5 off by just mentioning some of the things that we have 6 been doing. We have been quite busy since October 1. 7 There will be corrections to typographic and 8 grammatical errors. We also have to submit some 9 updates that weren't included in our October filing and 10 these are the terms and conditions of service. These 11 will be provided in a form system of account table that 12 was outstanding and a glossary of terms. 13 We have also been working on our data 14 and cost allocations since then. There are a number of 15 corrections that will be made and submitted. We have 16 looked at a categorization of the assets into the 17 network line connection and transformation and we have 18 sharpened our pencils and corrected a number of areas 19 that were discovered to have errors, the assignment of 20 the delivery points as a result of to-the-line 21 transformation connections have been changed and these 22 will be identified. 23 There are some aspects in terms of 24 the OMNA calculations which we have done to fit in with 25 the OEB approved transitional rateholder and some 26 additional work that was done. 27 MR. RODGER: Could you repeat that 28 for me? 19 1 MR. MIKHAIL: In Exhibit A of the 2 submission, it's Tab 5, Schedule 1, page 2, starting at 3 line 12 and in that paragraph we don't see any 4 reference to the Board direction that came in 5 RP-1998-001, which I think the date on it is March 6 15th, and it specifically says that the Board indicated 7 that one option should be investigated, which is: "Net 8 billing and the related backup charges". 9 They directed OHSC-OHNC to 10 investigate that and we are wondering why there was no 11 specific response to that. Was there any initiatives 12 done in that area and, if so, you want to share it with 13 us? 14 MR. CURTIS: I think this was 15 generally considered in the broad discussion and broad 16 examination of the net versus gross load issue and in 17 particular what we endeavoured to do was to get from 18 individual stakeholders the different options that they 19 considered should be applicable within the net versus 20 gross load resolution and to examine those. 21 As you will recall, during the July 22 workshop that we held, the decision was that there 23 should be a broad-based stakeholder group formed to 24 examine and develop different options to address the 25 net versus gross load issue and those were the ones 26 that we ended up examining and carrying forward. 27 There wasn't, to the best of my 28 knowledge, a stakeholder that brought forward that 20 1 specific option to examine, so it may not have had the 2 full consideration that the other options had. 3 MR. THIESSEN: Those are our 4 questions on that. 5 MR. RODGER: How do you propose that 6 we do this? I suppose we could go around the counsel 7 table first and then invite anybody from the audience 8 to come up to the microphone to ask questions? 9 MR. THIESSEN: Generally, it is done 10 in order of appearance. 11 MR. STEPHENSON: I am going to pass 12 on this for now. Thank you. 13 MR. MARK: No questions at this time. 14 MR. MIA: No questions. 15 MR. CAMPBELL: We don't have any 16 questions on Exhibits A and B. 17 MR. RODGER: Just one question, 18 perhaps for Mr. Poray. 19 Under the materials, particularly 20 with respect to rate design and connection charges, 21 there are two terms kind of used throughout the 22 documentation: connection point and delivery point and 23 actually the reference to delivery point was on your 24 last slide that you presented this morning. 25 Could you tell me, first of all, are 26 those two things the same? Is the connection point the 27 same as the delivery point? 28 MR. PORAY: Yes, it is. 21 1 MR. RODGER: And how would that be 2 defined? How do you define that term? 3 MR. PORAY: I think we defined -- in 4 our filing we defined what we meant by delivery point. 5 MR. RODGER: Could you point that out 6 for me, please, sir? 7 MR. PORAY: Just a clarification, are 8 we dealing with ANB first or are we now going into the 9 other parts of the -- 10 MR. RODGER: Well, this comes to the 11 next part, but you know the answer to it, let's answer 12 it anyway. 13 MR. ROGERS: Yes, because I think 14 part of it is as well. If this is going to be covered 15 off in the glossary of terms, that was the other issue, 16 when we were anticipating that this may come out, but 17 if you could refer me to where that definition is, that 18 would be helpful. 19 MR. CURTIS: It will be covered off 20 when the glossary is issued next week, but I think Andy 21 would be able to find the reference in the current 22 application. 23 MR. RODGER: That would be very 24 helpful. 25 Why don't we do this? Why don't we 26 handle it over the break. Martin will give it to you 27 at dinner somewhere. 28 MR. CURTIS: Fair enough, thank you. 22 1 Those are my questions. Thanks. 2 MR. FISHER: I have no questions. 3 MR. RODGER: Does anybody have any on 4 ANB or can we move on? Going once, twice, third, gone. 5 MR. MARK: Can I ask a clarification? 6 --- Laughter 7 MR. MARK: Does the ANB 8 (inaudible...)? 9 MR. CURTIS: Yes, it was covered off 10 in the presentation. Section B covers the stakeholder 11 consultation process and so that was my part of the 12 presentation and Section A provides the overview, the 13 summary of the application, as well as some of the 14 other administrative aspects of the application. 15 MR. DRINKWALTER: David 16 Drinkwalter -- don't forget the "l". 17 MR. CURTIS: Indeed 18 MR. DRINKWALTER: I have a couple of 19 points of clarification in terms of the definition of 20 the line connection and the contributed surplus by the 21 generator and I don't know if this is the time or not. 22 MR. CURTIS: They are actually 23 considered as part of Section D. 24 MR. DRINKWALTER: Okay. 25 MR. RODGER: It appears there aren't 26 any more question on ANB and so I suggest we move right 27 into Section C. 28 Ms Litt, do you have some questions? 23 1 MS LITT: Yes. In Exhibit C, under 2 Tab 3, I would like to go to page 1 first, please. I 3 have some questions about the principles and the 4 objectives as they are described at Tab 3. 5 On page 1, there are several 6 objectives or principles described at lines 7 and 8 and 7 then some new ones described at lines 12 and 13 and my 8 first question was are these principles or objectives 9 considered appropriate for companies applying for their 10 first cost allocation rate design decisions from the 11 regulator or are these more appropriate to companies 12 which have a history of coming before a regulator? 13 MR. PORAY: I think it was our view 14 that these are appropriate principles to start off with 15 and move into the new regulatory environment. 16 MS LITT: One of the authorities that 17 you quote in Tab 3 is Bondbright. Were there other 18 authorities that were canvassed? 19 MR. PORAY: I think this was the only 20 one that we considered. 21 MS LITT: And within Bondbright's 22 text, is there any hierarchy accorded to these 23 principles or objectives? Is there one which assumes 24 greater importance or is there one which OHNC accorded 25 greater importance to? 26 MR. PORAY: I think we treated all of 27 them on the same basis. 28 MS LITT: For the two new principles 24 1 that were identified, the enhanced flexibility and 2 practical feasibility that are described at lines 12 3 and 13, which authority did OHNC refer to in 4 identifying those? 5 MR. CURTIS: Could you restate that question, 6 again, Kathi? I'm sorry. I'm not sure -- 7 MS LITT: The new principles that are 8 identified -- and I have identified them as flexibility 9 and feasibility, as they are described at lines 12 and 10 13 -- I would like to know how those were identified, if 11 there was an authority that was referred to or if there 12 was a similar application in another jurisdiction that 13 was recognized as being particularly appropriate or if 14 there was another information source. 15 MR. CURTIS: I think that came about through 16 our stakeholder process. When we talked with the 17 different stakeholders, they brought forward this 18 prospective that there needed to be flexibility, in 19 terms of what was established, and so, that's one of the 20 drivers, if you will, to introduce this. 21 MS LITT: Are these attributes that you would 22 describe as "incremental" to the objectives or 23 principles described at line 7 and 8? Or would you 24 consider them as further refinements or specifications 25 of the principles? 26 MR. CURTIS: I don't think we considered them 27 to be incremental. But, basically, our treatment of the 28 principles was to try and waive them off or balance them 25 1 all off on an equivalent basis as we went through our 2 development. 3 MS LITT: Under Section 1.0, there's two 4 bullet points. They are at lines 19 and 20, and then, 5 on page 2, at lines 1 and 2 -- at line 1, rather. 6 Are these bullet points in order of priority? 7 Or must they also be respected as balancing each other, 8 neither one having priority over the other? 9 MR. PORAY: We would treat them as balancing 10 each other. 11 MS LITT: And for the bullet points that are 12 raised under Section 2.0, is there a hierarchy among 13 those bullet points? Or should they be considered a 14 balance set? 15 MR. PORAY: Again, as a balance. 16 MS LITT: In applying these objectives and 17 principles, when OHFC was -- when OHNC, pardon me, was 18 evaluating the cost allocation and the rate design that 19 followed, was it a case that a number of cost 20 allocations and rate designs were identified and then 21 they were compared back to the principles and some were 22 deleted? Or is it the case that anything that was 23 identified subsequent had to be consistent? 24 MR. PORAY: I think the latter. 25 MS LITT: Now, on page 3, at lines 3, 4 and 5, 26 there is recognition of rate stability and minimizing 27 impact on customers. The minimizing impact on customers 28 reference is page 2, lines 18 and 19. 26 1 How large a change in the proposed rates would 2 have to be observed or calculated before you would 3 consider that the rates were no longer stable? 4 MR. PORAY: I think we were looking -- when we 5 were looking at stability, it was on a year-by-year 6 basis rather than an actual magnitude. 7 MS LITT: On a year-by-year basis, then, how 8 large a change would have to be observed before rates 9 would not be considered stable? 10 MR. ROGERS: That calls for kind of a question 11 in judgment, Ms Litt, I wonder if you could let the 12 witness think about that a little bit and we will return 13 to it. I mean it really depends, I guess, on a lot of 14 factors. 15 MS LITT: It might be that this question is 16 appropriate -- more appropriately dealt with in the 17 interrogatories, as well. 18 MR. ROGERS: Maybe. It is something, I think, 19 that is highly customer-specific, I suppose, too, but, 20 in our judgement, it does require a little bit of 21 thinking. 22 So would you mind deferring that to an 23 interrogatory or -- 24 MS LITT: That's fine. 25 MR. ROGERS: -- let them think about it and 26 come back to it later? 27 MS LITT: That's fine. 28 MR. ROGERS: Thanks. 27 1 MS LITT: A somewhat different question, with 2 respect to rate stability and minimizing impacts: Are 3 there any market conditions which would have to be in 4 place for those objectives to have more relevance, 5 perhaps, rather than the first time that a cost 6 allocation and a rate design have has been brought to an 7 external regulator? 8 MR. CURTIS: Do you mean in terms of 9 infrastructure being put in place or -- 10 MS LITT: Possibly. 11 MR. CURTIS: -- systems and billing systems, 12 for example? Is that -- 13 MS LITT: Or if there were any more 14 theoretical constructs that would give rise to easier 15 price discovery, greater liquidity. 16 MR. CURTIS: I think our consideration, in 17 this, was more from the transition from a monopoly 18 situation to this unbundled new market situation that's 19 being created and it was our concern that, through this 20 transition, we needed to be mindful of any potential 21 rate shocks or rate disruption. 22 I think we could probably point, for example, 23 to the valuation that we made of locational transmission 24 pricing as introducing too much of a change moving from 25 the monopoly structure to the structure that we are now 26 talking about. So we didn't focus, if you will, in 27 terms of a future market structure where the systems had 28 been put in place where -- that the infrastructure for 28 1 the new marketplace had been fully put in place. I 2 think it would have been a problem for us to have tried 3 to evaluate it that way, given the work that's going on 4 now within the market design, through the IMO, and also 5 in terms of the other aspects that the Board itself is 6 undertaking around transmission system code, for 7 example. 8 MS LITT: With respect to rate shock, what 9 nature of change would constitute rate shock? Are you 10 thinking of the actual way that the rates are 11 structured, if you had gone from a per unit capacity 12 charge to a flat rate type structure, independent of 13 whether that had changed the customers's bills or not? 14 Or was it more in a quantifiable level? 15 MR. PORAY: I think it was the latter. 16 MS LITT: Thank you. 17 Also, on page 3 of Tab 3, at lines 7 and 8, 18 the bullet point states: 19 "The rate structure should minimize 20 impacts on the economic operation of the 21 electricity marketplace." (As read) 22 Can you amplify on that statement, please? 23 MR. PORAY: What we were thinking there is 24 that the rate structure that we should develop should 25 not create charges that would distort market signals for 26 the competitive electricity market because we are 27 dealing with recovery of embedded costs which are 28 separated from the energy marketplace. 29 1 MS LITT: Is there a test for the occurrence 2 of such distorting market signals? 3 MR. PORAY: Well, one test would be if we were 4 to charge on the basis of energy -- and you have an 5 energy market so there may be a confusion in terms of 6 the signals you are sending. 7 MS LITT: Now, this next question, I think, 8 properly belongs with principles, but it might not. 9 It's a process we identified at Exhibit D, Tab 10 5, on Schedule 1, page 2 -- and it's at lines 7 and 8 -- 11 and it concerns the efficiency of the generation. I 12 think I have the right reference. 13 MR. CURTIS: No, that's not our reference. 14 You said Exhibit D, Tab 5, Schedule 1, page 2? 15 MS LITT: Yes. 16 MR. CURTIS: Lines 7 and 8? 17 MS LITT: No, I'm sorry. You are right, I 18 don't have the right one. 19 MR. MIKHAIL: I think, definitely, it is 20 Exhibit D, Tab 5, Schedule 1, page 2, lines 17 to 19. 21 MS LITT: Thank you. 22 That's the discussion of generation that's 23 based on efficient technology. 24 Does the accommodation of generation based on 25 efficient technology arise from one of the specific 26 objectives and principles that's outlined at C, Tab 3, 27 Schedule 1? And can you point me to it, please? 28 MR. PORAY: We think that this is probably 30 1 addressed by the second bullet, under "cost allocation", 2 the principle -- the cost allocation should reflect cost 3 causality and the rate structure should minimize impacts 4 on economic operation of the electricity marketplace. 5 MS LITT: Were the other principles or 6 objectives identified by the bullet points effectively 7 traded off against these two, in respect to 8 accommodating generation based on efficient technology? 9 MR. PORAY: I think when we were looking at 10 that we were essentially trading off amongst all of the 11 principles. 12 MS LITT: Though no specific objective was -- 13 assumed diminished importance? 14 MR. PORAY: No. 15 MS LITT: But the two that you were trying to 16 fulfil were the cost causality and economic operation of 17 the marketplace? 18 MR. PORAY: Yes. 19 MS LITT: As a specific example there is an 20 objective of equity. That is stated at Exhibit C, Tab 21 3, Schedule 1, Page, line 8. 22 How did OHNC satisfy itself that equity had 23 been satisfied in trading off against all the different 24 objectives? 25 MR. PORAY: The way we did that is when we 26 were examining all of the options we tried to do it 27 essentially through the analysis and through the outcome 28 of those options, the rate design options. 31 1 MS LITT: Thank you. I would like to go onto 2 Exhibit C, Tab 4, please. 3 If OHNC had not adopted the pools construct, 4 what was the other option, or other options available? 5 MR. PORAY: Well, the other options would be 6 to go perhaps to cost-specificity. 7 MS LITT: What does that mean, exactly? 8 MR. PORAY: It means essentially trying to 9 allocate the cost to each customer that uses the 10 transmission system. We did a study which we call the 11 "locational transmission pricing", which actually does 12 that. 13 MS LITT: Does locational transmission pricing 14 proxy it or does it accomplish it or would locational 15 marginal pricing truly accomplish it? 16 MR. PORAY: I think you have to keep separate 17 the aspects of locational marginal pricing and 18 locational transmission pricing. 19 Locational marginal pricing is really the 20 value of the usage of the transmission infrastructure; 21 whereas locational transmission pricing is essentially 22 allocating the cost of the infrastructure to the users 23 on the most costs. 24 MS LITT: Okay. Once the pool construct had 25 been decided on, how were the pools parameterized? 26 MR. CURTIS: To some extent, again, this was 27 through our stakeholdering process. We looked at a 28 variety of different pools; some we felt were fairly 32 1 natural in terms of the structure of a transmission 2 system around network and connection, for example. We 3 also looked at other potential pools around generation 4 connection, for example, in metering. 5 The decision in our application to a certain 6 extent, anyway, was driven by the stakeholder opinions 7 that we -- again through our stakeholder process -- that 8 favoured the three pool concept. It has some merits in 9 terms of simplicity and being fairly straightforward, 10 for example. Those were items that were cited during 11 our stakeholder. 12 MS LITT: Can you direct me to the exhibit in 13 the evidence which specifically identifies the 14 boundaries between the pools? 15 MR. CURTIS: It is done diagrammatically at 16 the beginning -- 17 MR. PORAY: Exhibit C, Tab 6, Schedule 1, Page 18 2. 19 MS LITT: Yes. 20 MR. PORAY: Figure 1. 21 MS LITT: That is the one reference, correct? 22 MR. PORAY: (Nodding in the affirmative) 23 MS LITT: Was there any consideration 24 segmenting the pools into sub pools based on geography? 25 MR. CURTIS: I think we went straight to the 26 locational structuring, if you will. We didn't try and 27 take existing pool say, for example, around connection 28 and try and segment that into geographical areas. 33 1 MS LITT: Was there a reason not to? 2 MR. CURTIS: I think the results that we 3 foresaw would have been better represented through the 4 locational transmission. The results that we generated 5 through locational transmission pricing examples showed 6 that there were geographical clusters as far as costs 7 are concerned, and it would have been as reflective as 8 if we had taken that intermediate step in terms of 9 segmenting assets on a geographical basis, we felt. 10 MS LITT: A few moments ago you identified 11 that you considered a generators connection pool? 12 MR. CURTIS: Yes. 13 MR. PORAY: Yes, we did. 14 MS LITT: And that one was rejected and all 15 that is covered in the stakeholdering or was there 16 decision-making that occurred outside of the 17 stakeholder? 18 MR. CURTIS: I think there were both elements 19 in that, Cathy. 20 MS LITT: I would like to go onto Exhibit C, 21 Tab 5, please. 22 Will Schedule 1 of this exhibit be updated in 23 any way, or do you expect to update it? Tables 1, 2 and 24 3, for example. 25 MR. CURTIS: No. They are all straight out of 26 the approved rate order from the Board. 27 MS LITT: Any differences that arise in the 28 financial results, would they be captured through the 34 1 variance account? 2 MR. CURTIS: I don't think there will be any 3 changes as far as the financial results in terms of this 4 update that we are going to be making. 5 MS LITT: I am thinking in June of 2000, 6 though, once there is perhaps four months of actual 7 results that have been settled on and perhaps they are 8 different. 9 MR. CURTIS: You mean in our next application? 10 MS LITT: Yes. 11 MR. CURTIS: Yes, we would do that, then. 12 MS LITT: Thank you. 13 MR. THIESSEN: I just quickly have a couple of 14 questions on Tab 6. On Page 5 of Schedule 1 of Tab 6, 15 with regard to metering, the evidence states that the 16 details of these costs are not sufficiently developed to 17 proceed with a separate metering cost pool for 18 developing charges at this time. 19 I know during the summer in the stakeholdering 20 and I think in report of the net load, net gross 21 advisory group, you did identify a pool for metering, at 22 one point. I am wondering why that didn't appear in 23 your proposal at this time? 24 MR. PORAY: Basically, the problem is that we 25 have not been able to split, at this point in time, the 26 costs of the meters themselves from the metering 27 infrastructure. That still has to be done. The 28 information that we have or that we had prior to the 35 1 submission did not allow us to split the metering costs 2 from the infrastructure costs. 3 And since metering is going to be contestable 4 when the market opens, it is necessary to separate those 5 costs. That is why we were not ready yet to do that. 6 MR. CURTIS: Also through the stakeholdering 7 it was fairly clear to us that stakeholders weren't 8 interested in us coming out with an average cost for 9 meters. The desire was to have meter costs calculated 10 on the basis of what customers were actually making use 11 of as far as meter service. 12 MR. THIESSEN: My next question involves 13 connectivity data base output table, which is Schedule 2 14 of that exhibit. It is that long, I think, 47 page 15 table that identifies each asset and which pool it is 16 assigned to. 17 We had a concern that there wasn't enough 18 background documentation on those assignments of assets 19 to the pools -- that we aren't able to actually look to 20 see that or test your evidence in a sense that we are 21 able to look at an asset, actually find out what it is, 22 apart from your naming of it, and also identifying the 23 dollar amount or the value of each asset as it is 24 assigned to the pool. 25 Likely you will not be able to provide this 26 today, but I just wanted to mention that in a sense that 27 we will likely be asking an interrogatory requesting 28 that kind of detail, at interrogatory time -- just to 36 1 let you know that we would like to have that kind of 2 detail in the evidence. 3 MR. CURTIS: Yes. It will be available at 4 that time. 5 MR. THIESSEN: And my last question has to do 6 with Schedule 3 and Schedule 4 of that same tab. It 7 talks about the functionalization of split stations and 8 functionalization of assets, connections to generators. 9 I found it curious that these were defined as split 10 assets, yet in the tables a number of the assets and 11 that 100 per cent in one category. I'm wondering why 12 you refer to them as split assets if they are 100 per 13 cent in one category. Therefore, I thought they might 14 appear in Schedule 2 as clearly identified assets. 15 MR. CURTIS: I think we are talking about 16 perhaps a two stage process. The first stage in our 17 process was the functionalization of assets, so you end 18 up in these instances with them being split, but you 19 move on to ultimately an allocation process that takes 20 place. You could in certain circumstances see that in 21 the allocation process that they end up in one pool. I 22 think maybe that's what's being reflected in your 23 comment. 24 MR. THIESSEN: All right. Thank you. Those 25 are the questions of Board staff on Exhibit C. 26 MR. STEPHENSON: No questions, thank you. 27 MR. MARK: No questions, thank you. 28 MR. COBURN: No questions. 37 1 MR. MIA: No questions. 2 MR. CAMPBELL: Could you turn up tab 6, 3 Schedule 1, page 4 and there at lines 6 through 8 you 4 indicate that the remain component assets were allocated 5 to the respective function based on the net book value 6 of the specific equipment identifiable to the function. 7 Could you describe in a little more detail, please, what 8 was considered in making that allocation? 9 MR. PORAY: Yes. What this entailed was 10 assets which perform a number of functions. We tried to 11 identify specifically what functions they performed and 12 allocate the assets to that function. For instance, if 13 you had a TS that also had a distribution station at it, 14 we would allocate a part of that to line connection and 15 a part of it to network. I'm sorry, not a distribution 16 station but a step down from above, 50 KV to below 50 KV 17 for distribution purposes. That would be allocated to 18 transformation, say, whereas the rest of the station 19 would remain in the network. 20 MR. CAMPBELLL: And were there any particular 21 criteria that you used in making that split? 22 MR. PORAY: Well, again, in identifying the 23 functions that this equipment performed. 24 MR. CAMPBELL: If you turn to Schedule 3, if 25 you look down that schedule behind tab 6, would it be 26 possible for you to illustrate how, using an example 27 from that table? 28 MR. PORAY: For instance, J. Clark Keith TS 38 1 transformer stations, a part of its step down voltage 2 from above 50 KV to below KV and that is then -- that 3 performs a transformation function whereas the rest of 4 it is really performing a network function. It's 5 switching facilities. 6 So on one side you have a facility that 7 performs a number of functions. 8 MR. CAMPBELL: And that similar exercise was 9 gone through for each of the assets on this list, so you 10 would really have to get right into the facilities at 11 each of these stations in order to try and understand 12 this. There is no sort of, other than the kind of thing 13 you talked about where you pick a particular voltage and 14 on that basis allocate it. Other than doing that kind 15 of detailed exercise, there is no sort of general 16 criteria. 17 MR. PORAY: Well, you start off by determining 18 what are the guidelines for the assets, for allocating 19 the assets to the network, the line connection and the 20 transformation connection and you go through your asset 21 database and you perform those allocations and there 22 will be a number of assets that are left over which 23 cannot clearly be identified one on to the other. 24 Then you go into those assets. You examine 25 those in more detail. 26 MR. CAMPBELL: All right. If we can go then 27 to Exhibit C, tab 7. There at page 4 of Schedule 1, in 28 the second paragraph on that page you describe the 39 1 process used to allocate the net book value for plant 2 projected to enter service in 2000 and the 2000 OMNA. 3 Again, could you give us a little more 4 description of the basis on which these costs were 5 assigned to the three pools and again in particular I'm 6 wondering whether there were any specific assignment 7 criteria used. Just to sort of tell you where I am 8 leading with this is we are curious as to whether the 9 basis for assigning these costs was different from that 10 used for the direct assignment of plant in service. 11 MR. PORAY: The basis for assignment should be 12 the same because these are costs directly identified 13 with the assets and, therefore, can be assigned to those 14 assets, but there are other costs which cannot be 15 directly assigned to those assets. Those costs will be 16 allocated. 17 MR. CAMPBELL: Can you explain in a little 18 more detail the criteria you used in making that 19 allocation? 20 MR. PORAY: `If you go back to page 1 of 21 Exhibit C, tab 7, Schedule 1, we define what we mean by 22 directly assigned costs, unassigned costs and allocated 23 costs and allocate this and on the basis of that we did 24 the assignment and the allocation. 25 MR. CAMPBELL: And was that process different 26 for assigning the 2000 OMNA referenced on page 4 as 27 compared to the OMNA that's described at page 3, lines 28 12 to 13? Is there a different between those two 40 1 exercises? 2 MR. PORAY: Yes. The exercises were done 3 separately, but the same rules were applied. 4 MR. CAMPBELL: All right. If could take you 5 then to page 10 again of Schedule 1, tab 7. My question 6 here is just for clarification. There you refer to 7 three initial allocation factors and that's in line 8 eight. Our understanding is that those three factors 9 would be the net book value, your OMNA and depreciation. 10 Do I have that correct? 11 MR. PORAY: That is correct. 12 MR. CAMPBELL: And a little farther down on 13 that page at line -- under the heading "Rate base 14 allocation factor", you indicate -- I guess our question 15 is whether the directly assigned net book value was 16 included in the calculation of the rate base allocation 17 factor. We weren't clear on reading this. 18 MR. PORAY: Yes, it was. 19 MR. CAMPBELL: Thank you. Those are our 20 questions on Exhibit C. 21 MR. CURTIS: Do we want to pick up your 22 earlier question you were asking in terms of the 23 definition of the delivery point versus a definition of 24 the connection point? 25 MR. RATTRAY: That's correct. 26 MR. CURTIS: Could we refer you to Exhibit B, 27 tab 9, Schedule 3. This is our transmission 2000 paper 28 that we issued fairly early on in the stakeholder 41 1 consultation process. 2 MR. RATTRAY: Could I have the reference 3 again, please? Sorry. 4 MR. CURTIS: Certainly. Exhibit B. 5 MR. RATTRAY: Yes. 6 MR. CURTIS: Tab 9, Schedule 3. 7 MR. RATTRAY: Yes. 8 MR. CURTIS: And if you go to the back of 9 that, page 69, where we have a glossary. 10 MR. RATTRAY: Yes. 11 MR. CURTIS: We have defined, if you see about 12 half way down that page, we have defined delivery point. 13 MR. RATTRAY: Page 69? 14 MR. CURTIS: Page 69, yes. 15 MR. RATTRAY: It starts with a D, I believe. 16 MR. CURTIS: Okay can we go through the 17 sequence again. This is Exhibit B. It is in one binder 18 that is all of Tab 9. And it is Schedule 3 and then at 19 page 69 and it is about the mid-point of that page that 20 we have delivery point. 21 MR. RATTRAY: See and that states the point of 22 supply to the customer or group of customers from the 23 transmission system. 24 MR. CURTIS: Yes, and we have used that 25 synonymously with connection point. 26 MR. RATTRAY: And is there any more 27 specificity, do you think, that will be forthcoming 28 beyond that definition like more precisely with respect 42 1 to the meter or, for example, if it is an LDC, is it 2 more the transformation, is it the meter, is it the high 3 side, the low side? 4 MR. CURTIS: Typically it is the meter and it 5 would -- I think it is on the low side, is it? 6 MR. MARK: On the low side. 7 MR. RATTRAY: The low side meter, and is that 8 then the specific definition that parties can rely on 9 for your entire submission in this proceeding for 10 delivery point? 11 MR. CURTIS: Yes. 12 MR. RATTRAY: Thank you. 13 MR. SMELSON: I have one question and some 14 follow-up, perhaps with respect to Exhibit C and the 15 reference I would like to start from is Exhibit C, Tab 16 6, Schedule 1. 17 On page 3 -- and that is where there is a 18 definition of transmission and line connection -- it 19 says: 20 "The connection facilities are radio 21 parts of the high voltage system owned by 22 OHNC that are specifically dedicated to 23 serving a single customer generator or a 24 group of customers or generators who are 25 connected to the transmission network via 26 these connection facilities". (As read) 27 And is this the definition of transmission 28 line connection that we should rely upon? 43 1 MR. PORAY: Yes. 2 MR. SMELSON: Did you test this definition in 3 your consultation program with alternative definitions 4 of line connection? 5 MR. CURTIS: I think we did hear that there 6 were other proposed definitions for that point. This is 7 the definition, though, that we came up with that we 8 felt that we could consistently use and to some degree 9 it is in terms of consistency with regard to the way our 10 database was structured. 11 MR. SMELSON: As you know, EMPCO represents 12 the industrial customers, and many of the industrial 13 customers have been very surprised by this definition. 14 They think of that connection facilities as being the 15 facilities that supply them exclusively, that supply 16 just one customer, whereas this definition includes 17 lines that supply quite large groups of customers. 18 MR. PORAY: Yes. 19 MR. SMELSON: Did you consider using the 20 narrow definition of the connection as the lines that 21 supply just one customer rather than a group of 22 customers? 23 MR. PORAY: This goes to the heart of the 24 matter in terms of how do you define the facilities, 25 whether it is a shallow connection or whether it is a 26 deep connection. 27 In the way we started the process was to start 28 off with network and define the network facilities as 44 1 being those which are common to all the users on the 2 transmission system. 3 So all of the 500 KV facilities would be 4 shared by all users and then we would look at where the 5 next set of facilities or the 240 KV and its varying 6 power with the 500 KV system, then these also serve a 7 common function and we went down and identified all of 8 those facilities. 9 So that then created a pool of facilities that 10 represent the network. And we identified the 11 transformation stations and the transformation 12 facilities which essentially step down from above 50 KV 13 to below 50 KV to supply customers. 14 So that then created the transformation 15 facility function and then what was left over were the 16 radio lines that served customers and those we call 17 connection lines. 18 MR. SMELSON: There is a test, I believe, that 19 you have at some times used of disconnecting an 20 individual customer and treating as connection 21 facilities those lines on which the path low goes to 22 zero when you disconnect that customer. I believe you 23 have at times used that as a definition of connection. 24 MR. PORAY: I think in the past we have, yes. 25 MR. SMELSON: You didn't consider that in this 26 particular case. 27 MR. PORAY: No. 28 MR. SMELSON: Your definition of connection, 45 1 if I can refer to that, is a broad definition of 2 connection. With that broad definition, as you propose 3 in this proceeding, I believe that most of the 115 KV 4 system in southern Ontario is classified as connection. 5 Is that correct? 6 MR. PORAY: A large portion of it would be 7 yes. 8 MR. SMELSON: And would I be correct that most 9 of these lines at the times they were built if they had 10 been allocated a network of connections at that time, 11 according to your current definitions, would have been 12 allocated as a network at that time? 13 MR. PORAY: At that time, they would have, 14 yes. 15 MR. SMELSON: The only other question I had in 16 this area, I believe has already been asked by board 17 staff, I was going to ask for some more detail around 18 the connectivity database, Exhibit C, Tab 6, Schedule 2 19 and just to let you know that we also will be asking for 20 more information around that. 21 Thank you. 22 MR. RATTRAY: Does anyone else have questions 23 on Section C? If not maybe we can take a break and then 24 do Section D. 25 MR. DRINKWALTER: I have a question. 26 MR. RATTRAY: With an "l". 27 MR. DRINKWALTER: With an "l", you are right. 28 Some things don't change over the years. If I 46 1 can get you back to this line connection issue. Exhibit 2 C, as in Charlie, Tab 6, Schedule 1, page 2 and page 3. 3 I guess I am having trouble reconciling in my 4 mind the definition of the line connection with the 5 diagram. How many line connection pools do you 6 visualise, one or more than one? 7 MR. PORAY: Well, as one moves towards more 8 cost specificity you could break it down into sub-pools. 9 MR. DRINKWALTER: So your long-term are many 10 pools, but this hearing is one pool? 11 MR. PORAY: For this application we are 12 proposing one line connection pool. 13 MR. DRINKWALTER: Now can you lead me through 14 the diagram? What is the line that would be considered 15 as the line connection? 16 MR. PORAY: The line connection would be, if 17 you look at the line which is going down to the 18 industrial customers or direct customers from the 19 network, these are the lines going, if you like, South. 20 One is going through a transformer and one is going 21 directly. 22 Those would be radio facilitators that I would 23 call line connections. 24 MR. DRINKWALTER: So if I understand that 25 right, the first one at the bottom of which it say, "low 26 displacement generation", that is considered a line 27 connection even though it is in the transmission network 28 box? 47 1 MR. PORAY: Well, it is leading from the 2 transmission network to a customer. It is a radio 3 connection to a customer. 4 MR. PORAY: The second one. Again, going from 5 the station to the customer -- in other words, the 6 parallel line that goes through our transformer 7 station -- would be considered a line connection, too. 8 MR. DRINKWALTER: Is that just from the 9 transformer station down? Or does it take off from -- 10 MR. PORAY: No, the example intended here is 11 that it would be from the transformer station. 12 MR. DRINKWALTER: That's from the transformer 13 station? 14 MR. PORAY: Yes. 15 MR. DRINKWALTER: So the line from -- that 16 solid line inside the transmission network box down is 17 considered network? The inverted L shape? 18 MR. PORAY: No. No. That would be a line 19 connection. 20 MR. DRINKWALTER: That is a line connection, 21 too? 22 MR. PORAY: Yes. 23 MR. DRINKWALTER: So it runs from that 24 vertical solid line, just inside the transmission 25 network, to the transformer station, and then from the 26 transformer station to the customer, both of them. 27 What about the line at the top? 28 MR. PORAY: The line at the top would be 48 1 considered a connection, as well, to -- in this 2 particular case, it would be a distribution company. 3 MR. DRINKWALTER: Just to make sure I 4 understand it, it runs from that solid line, just inside 5 the transmission network, to the transformer station, 6 from the transformer station to the next transformer 7 station that's in the distribution box? 8 MR. PORAY: It's from the box to the -- from 9 the box which is at the edge of that box, or the 10 transmission network, going east, I guess, through the 11 box through the transmission connection. That would be 12 a transmission line connection. 13 MR. DRINKWALTER: What happens beyond that 14 transformer station that's in the connection box? Is 15 that line that proceeds from there, through to a 16 distribution station or a station that's in the 17 distribution box, is that also a line connection? 18 MR. PORAY: Yes; the intention here was really 19 not to show a line going to the distribution facility as 20 much as to say that this is a -- that the distribution 21 utility would take off from the transformation station 22 which is a transmission connection. 23 MR. DRINKWALTER: But I guess my question is 24 that, this line that runs from the transformer station, 25 shown within the connection box, running from that 26 transformer station to the transformer station shown 27 within the (off microphone). 28 Is some or all of that included in the line 49 1 connections (off microphone)? 2 MR. PORAY: Yes. Yes, it would. 3 MR. DRINKWALTER: And where would it end, 4 then? 5 MR. PORAY: It would end at the customer -- at 6 the distribution utility's gate. 7 MR. DRINKWALTER: Okay. Thank you. 8 MR. FAGAN: Thank you. 9 Bob Fagan. 10 I just have two questions. The first one is 11 in reference to Exhibit C, Tab 6, Schedule 1, page 205. 12 The same diagram. 13 There are no other large transmission maps 14 included in the application? Is this the only diagram 15 that addresses that? 16 MR. PORAY: I believe that there is a 17 geographical map showing the transmission facilities in 18 the province in Exhibit B. 19 MR. FAGAN: In Exhibit B. 20 MR. CURTIS: No, actually, it's in "A". 21 MR. FAGAN: I'm sorry. "A". 22 MR. CURTIS: Tab 4. 23 MR. FAGAN: Will there be wall-sized maps made 24 available that would provide a lot more detail than this 25 diagram, in terms of where line connection facilities 26 are, where network facilities are? 27 Like, for example, I have a large schematic 28 diagram of the system and I have the MPCC transmission 50 1 map. But what I don't have and what I would find very 2 useful would be a large, wall-sized map, with 3 geographical overlay, of the entire system, showing as 4 much information on where is the network lines, where is 5 the connection lines and the boundary lines. 6 MR. CURTIS: Just for clarification, Bob, the 7 maps that you do have right now are, again? You have 8 our bulk electricity system diagram with -- 9 MR. FAGAN: I have that. That's the 10 schematic. A very good schematic. And then I just have 11 the general MPCC diagrams. 12 What I haven't been able to easily lay my 13 hands on would be a large, wall-sized, geographical map 14 that shows everything down to the 115 level, and perhaps 15 a little bit below that. Or a set of maps. 16 MR. CURTIS: I think, probably, the issue is 17 more around logistics. I mean we do have a 18 geographical-based map, wall-sized, like the one that 19 you are describing. It might be a bit of a challenge, 20 though, for us to be able to provide it to all of the 21 intervenors and that, so. Maybe we could -- we could 22 certainly make one available within -- it is a 23 wall-sized map. It is a large map. 24 We don't want to give it to everybody because 25 it will be impossible to do that; it would be very 26 expensive. But we will make one available to you and we 27 will try to see if we can have one available here for 28 the hearing. How's that? 51 1 MR. FAGAN: Okay. That would do. I mean what 2 I'm used to, in the States, is that this type of 3 information is filed at the FERC, is made available to 4 all intervenors, and I find it very helpful, as a visual 5 reference, when I'm going through all this material. 6 But I will leave it at that. 7 My second question. Exhibit C, Tab 4, 8 Schedule 1, page 3, lines 6 through 8. There's just a 9 reference there to the generation connection charges and 10 whether or not they should be isolated or whether or not 11 there should be a separate pool. 12 Is there, anywhere in that application, an 13 isolation of those charges? Or if the -- in response to 14 the staff's question about the connectivity database, 15 once that information is provided, will that be easily 16 computable or provided to stakeholders to get a sense of 17 what the magnitude of that potential generation supply 18 pool might be? And the documentation around that type 19 of a computation. 20 MR. PORAY: I think as part of the request to 21 the Board that information would be made available. 22 MR. FAGAN: Okay. Thank you. 23 MR. DRINKWALTER: David Drinkwalter again. 24 Just one other question. I think it's in "C"; 25 I'm not sure. 26 Where do you include the 25-cycle system, and 27 as what? 28 MR. PORAY: It's definitely included. I mean 52 1 parts of it will probably be in network and parts will 2 be in line connection. 3 MR. DRINKWALTER: Really? And since I didn't 4 see it described any place, could you tell me where it 5 is and the number of customers it serves? 6 My understanding is it's very isolated and 7 serves very few industrial customers. 8 MR. CURTIS: Sort of geographically, it's in 9 the Niagara Region, sort of the Golden Horseshoe Region, 10 kind of south and -- 11 MR. DRINKWALTER: Roughly from Hamilton -- 12 MR. CURTIS: -- and east -- 13 Yes. Down in that area. 14 I'm afraid I don't have, right now, the actual 15 number of customers that are served off the 25 hertz 16 system but -- I mean you are qualitatively correct, it's 17 a relatively small number. 18 MR. DRINKWALTER: Is that the only part of the 19 system that's left, is that one in Priest, from 20 Hamilton -- 21 MR. PORAY: No; I think there are parts in the 22 northeast, around Sudbury, as well. 23 MR. WHITE: I'm Roger White, from ECMI. 24 I would like to pursue these gentlemen and I 25 would like to take you to Exhibit C, Schedule 1, page 1. 26 I would like to hear each of you gentlemen talk for a 27 minute about fairness and equity and how it would apply 28 and whether it would be reciprocal, in terms of its 53 1 application, to end-use customers, as it would be 2 expected to be with respect to yourself, as a company. 3 MR. PORAY: I'm sorry. I don't understand the 4 question. 5 MR. WHITE: Let me suggest to you for a minute 6 that in the use and the management of the transmission 7 system, that you order a distributor or an end-use 8 customer to remove facilities from something that would 9 supply them on a network basis and move them to a 10 connection type cost pool to save the transmission 11 system company some money in terms of capital 12 investment. Would that be fair and equitable? And help 13 me understand why it would or wouldn't be. 14 MR. PORAY: I am not aware of our company 15 having done anything like that. 16 MR. WHITE: I am. 17 MR. ROGERS: Well, Mr. White, this really 18 isn't the place for -- 19 MR. WHITE: No. I am trying to understand 20 fairness and equity and would that be fair and 21 equitable -- 22 MR. ROGERS: Plato did, too, but it was a long 23 time ago. 24 MR. WHITE: You ask him -- example. 25 MR. ROGERS: Well, what is your question 26 again. I don't want to enter into some philosophical 27 debate with you about fairness and equity unless we have 28 got some technical point to it. 54 1 MR. WHITE: It does in terms of how customers 2 are supplied and if customers are required by the 3 transmission system to move from one connection pool to 4 another connection pool which might be more expensive, 5 is that fair and equitable -- if it is the transmission 6 system that saves money? 7 MR. ROGERS: I mean it is a hypothetical 8 question. If you have got -- 9 MR. WHITE: No, I can give you a specific 10 example. 11 MR. ROGERS: Well, if you would let me finish 12 my -- 13 MR. WHITE: Sorry. 14 MR. ROGERS: -- sentence. If I could remember 15 what it was, I would finish it -- 16 --- Laughter 17 -- very eloquently. So, let's not get into an 18 argument about this. If you have a specific example 19 that is bothering you, put it to us in interrogatory and 20 we will try to answer it. 21 MR. WHITE: Okay. I will hold my questions 22 for the interrogatory. 23 MR. ROGERS: If you just give us -- no, make 24 it specific so that they know exactly what the 25 parameters for this individual customer are and we will 26 do our best to answer it. 27 MR. WHITE: The customers have participated in 28 LURP programs. Are you familiar with what those are? 55 1 Local utility resource planning -- 2 MR. ROGERS: Yes. 3 MR. WHITE: -- with Ontario Hydro. 4 MR. CURTIS: I think they were LIRPs, weren't 5 they? Local Integrated -- 6 MR. WHITE: Yes. Okay. Fine. 7 MR. CURTIS: Okay. Just to confirm. 8 MR. WHITE: And by participating in that 9 process, Ontario Hydro transmission facilities were -- 10 saved money? 11 In many cases, it was intended -- the purpose 12 of this was intended to reduce transmission system costs 13 and defer transformer stations and this type of thing? 14 MR. CURTIS: In fact, I think the LIRP process 15 was set up so that Ontario Hydro, as a provider of 16 transmission and energy services to various customers, 17 could get together and determine what the best most 18 economical decision would be in terms of further 19 development of the system in that local area. That was 20 always the objective of local integrated resource plans. 21 It is just that -- I guess the thing I am 22 having a little problem understanding is the idea that 23 we would have forced anybody to -- you know, off one 24 option to another option. It was a process that was set 25 up to try and arrive a collective decision. 26 MR. WHITE: In most of those cases were not 27 the transmission system cost the most effective -- the 28 most expensive costs in terms of the components? 56 1 Therefore, it drove distributors and others into 2 building distribution system costs in lieu of the more 3 expensive transmission system costs. Was that not the 4 normal general outcome? 5 MR. CURTIS: No. Actually, I think, what ends 6 up happening or what ended up happening in most of 7 these, there would be a generation option. There would 8 be -- there may be many transmission options, there may 9 be many distribution options, there may be many demand 10 management options -- and the whole purpose of the LIRP 11 process was to try and arrive at what was the best most 12 economic solution overall to the problem that was 13 identified in that local area. 14 In some instances, some of the transmission 15 alternatives would have been the most expensive, but I 16 wouldn't ever characterize that as being the case all 17 the time. 18 MR. WHITE: One of my clients was, in fact, 19 ordered to move load from what is clearly a transmission 20 system station on to what is classified a high voltage 21 DS in the allocation of assets within Ontario Hydro 22 Services company. 23 Would you agree that that would ultimately 24 result in customers seeing a higher bill particularly 25 seeing how that transformation station was a -- would 26 probably be identified as a network asset? 27 MR. CURTIS: You mean a connection asset, 28 don't you? 57 1 MR. WHITE: No. The initial trans -- 2 MR. CURTIS: The initial connection -- 3 MR. WHITE: -- transponder station -- 4 MR. CURTIS: -- was that -- that was what 5 would be in an area that would be classified as 6 networked under our application. 7 MR. WHITE: Exactly. 8 MR. CURTIS: And you are saying that that 9 customer had to move his connection point to what would, 10 in our application, be termed as a connection facility. 11 MR. WHITE: Yes. It is down in the 12 distribution side of the asset pool. 13 MR. CURTIS: Yes, and -- 14 MR. WHITE: Yes. 15 MR. CURTIS: I don't know the specifics of the 16 example you are talking about. 17 MR. WHITE: Let me suggest to you it was the 18 capacity limitation at the transformation station. 19 MR. CURTIS: Yes. 20 MR. WHITE: The network one. 21 MR. CURTIS: Yes. I don't know the specifics 22 of the example that you are talking about, but if you 23 are saying that a customer was moved from a network 24 facility to a connection facility, then, yes, under our 25 application, that customer would be paying more for the 26 transmission charge. 27 MR. WHITE: Now, is that fair and equitable 28 based on the words that are in this schedule? 58 1 MR. ROGERS: Well that is -- I'm going to have 2 to intervene here. I'm sorry Mr. White but I really 3 think you are being argumentative now and -- 4 MR. WHITE: No. I am -- 5 MR. ROGERS: -- that is not the purpose -- 6 just a minute. Would you please listen to me? 7 MR. WHITE: Sorry. 8 MR. ROGERS: That is not the purpose of 9 today's proceeding. If you have technical questions to 10 ask these witnesses, they will do their best to answer 11 them. 12 But that is not what you are doing now, with 13 great respect. You are arguing with them about a 14 specific application and a hypothetical case and they 15 don't know all the facts. 16 It is not very productive and of little 17 interest to anybody else, I don't think, here. 18 I hate to do it, but I am going to object to 19 this line of questioning. 20 MR. WHITE: Okay. I will withdraw the 21 question. 22 MR. ROGERS: And you will be welcome at the 23 appropriate time, too, Mr. White. 24 MR. THIESSEN: I think we will break now. I 25 don't know whether exhibit C is done, but why don't we 26 break at this point for 15 minutes and come back at 27 about 20 after 11? 25 after 11. 28 --- Upon recessing at 1107 59 1 --- Upon resuming at 1130 2 MR. THIESSEN: Gentlemen, can we get started, 3 please. We would like to get started again. 4 I have at least one housekeeping item. That 5 is I have arranged for a hot line phone number for this 6 hearing. The number is 440-7646. There is no voice 7 mail on that. There is no message on that right now. 8 By the end of the day we hope to have a message on there 9 just detailing some of the key dates for the hearing and 10 any sort of news updates that come around. You can 11 phone that number. That's 440-7646. 12 One other item is that a photographer from 13 IPSO is here and would like to take a few photographs 14 for the IPSO Facto Newsletter. If no one objects, Jake 15 Brookes may take a few photos. Just briefly and 16 unobtrusively. 17 MR. ROGERS: I can say as well before we 18 resume that considering this wall-size map, we will 19 arrange to have a wall-size map of the transmission 20 system available for viewing here at the Ontario Energy 21 Board. It will be in our Library or some place here so 22 that it can be viewed by the public. We will also 23 arrange to have one here for the hearing itself in the 24 hearing room so that everybody can see it. It will take 25 a little while to get that. It will take a few weeks 26 before we can get that together. 27 MR. THIESSEN: Are there any objections or 28 questions about the map availability issue? 60 1 MR. FAGAN: Is there any way that we could 2 have reduced sized maps? 3 MR. ROGERS: Let us take it under advisement. 4 We will look to see just what we are able to produce in 5 terms of a wall-size map and then see whether it is 6 feasible to shrink it down to some usable format for 7 you. I don't want to commit to do it until we see 8 whether or not it is feasible, but we will look into 9 that. Okay? 10 MR. THIESSEN: I'm sure, if you are just 11 talking one or two maps for certain really interested 12 intervenors to work on in detail, then maybe you can 13 provide those instead of providing them to every single 14 intervenor. We will discuss that and we will get back 15 to you. 16 MR. ROGERS: Are there any other questions on 17 Exhibit C before we move to Exhibit D? 18 MR. RODGER: If I could ask one more question, 19 that I perhaps should have when it was my turn the first 20 time around. I believe it falls in the cost allocation. 21 Toronto Hydro is one of the few utilities in 22 the province, I believe -- I understand Ottawa Hydro is 23 also in this case -- where they own and operate low 24 voltage switch gear hydro stations. Up until this time 25 Toronto Hydro had been receiving credit for this 26 service. In Toronto Hydro's case, my understanding is 27 it's significant in the credits, in the millions of 28 dollars per year. 61 1 Can you tell me where that issue is dealt with 2 in this application? 3 MR. PORAY: This issue is not dealt with in 4 this application, but I think we recognize that it is an 5 issue for those utilities that own switch key and 6 perhaps the thing would be to take this off line and try 7 and work with those utilities on what options would be 8 available to go forward. 9 MR. RODGER: Is there a reason why you felt 10 that it wasn't appropriate for this application? 11 MR. CURTIS: No. I don't think it's a 12 question of not being appropriate. I think it's just 13 that we hadn't considered it in terms of the application 14 and what we are I think offering is to meet with the 15 utilities and develop a position that we can carry 16 forward to the Board on this particular issue during 17 this proceeding. 18 MR. RODGER: It is your view this would be 19 something that we could perhaps start discussions with 20 outside this process. 21 MR. CURTIS: Well, I guess what we are 22 suggesting is that it would be resolved through this 23 process, but since it hadn't been raised before now and 24 we hadn't considered it in terms of developing this 25 particular application, I think we need to have some 26 discussions with the utilities to try and develop what 27 the resolution of this issue would be. 28 Just for your information, and I know you have 62 1 seen a lot of material, but I am aware that Ottawa Hydro 2 did send a letter to Ms Clitheral on July 7, 1999, 3 raising this issue so just for your information -- I can 4 give you a copy of that afterwards, but I know that at 5 least Ottawa has raised this in the past, this summer. 6 MR. RODGER: I think we are aware of that. 7 Any other questions on C before we move to D? 8 Very good. Then let's move to D, shall we? 9 MS LITT: I would like to start with tab 2, 10 please, point of filling for transmission. Under the 11 proposal, are there meters at these point of billing 12 sites such that the capacity and energy can be metered 13 or would be necessary to accommodate the "metering" 14 through a simulation and make provision for a true-up at 15 a later date? 16 MR. PORAY: I think in most cases there are. 17 There may be some where the meter is in a different 18 position. 19 MS LITT: So those where the meter is in a 20 different position, how would you determine the capacity 21 and energy to suit? 22 MR. PORAY: Well, there is a methodology 23 through the market rules that are being developed just 24 now that that would take account of that. 25 MS LITT: Okay. Now, in Exhibit D at tab 2 in 26 Schedule 1, could you turn to page 9, please. Lines 6 27 through 8 refer to considerable complexity in 28 implementing end use customer based filling. Can you 63 1 identify the specific complexities or take me through 2 the transaction step by step and tell me where the 3 incremental complexities occur? 4 MR. PORAY: Basically the complexity is in 5 recognizing the fact that transmission is being charged 6 on the basis of demand. A lot of retail customers are 7 charged on the basis of energy, so there will be the 8 methodology of translating some of the demand charged to 9 an energy charge. The complexity would also be in just 10 the sheer number of bills that would have to be sent to 11 the retail customers. 12 MS LITT: Was there anything that was 13 addressed in either MDC or the retail settlement code 14 that spoke to the point of billing and guided OHNC in 15 determination? 16 MR. PORAY: Yes. The MDC did address this and 17 the recommendations were that transmission would be 18 billed at the TND boundary. 19 MS LITT: Do you have a reference for the MDC 20 report that sets that out? 21 MR. PORAY: I think this is in the final. I 22 don't have that reference directly with me, but it will 23 be in the final report, the fourth quarter report. 24 MS LITT: I would like to go on to tab 3, 25 please. This is the definition of the transmission 26 customers. The proposal is to continued status quo 27 definition. Is that meant to be a transitional 28 definition or is that the definition OHNC proposes to 64 1 apply in the long term? 2 MR. PORAY: OHNC's proposal for the long term 3 would be that transmission customers are those who are 4 directly connected to the transmission system, but we 5 recognize that there are a lot of issues to be sorted 6 out going from the present arrangement to the future 7 and, therefore, we propose for this application to use 8 the status quo definition. 9 MS LITT: What are the top three issues that 10 would have to be resolved before the directly connected 11 definition could be implemented? 12 MR. PORAY: I think really the key 13 considerations are the fact that there are different 14 players involved in this. There is the IMO which 15 effectively will be the transmission service provider 16 and will be billing for transmission services, those 17 market participants who participate in the marketplace. 18 Then there are the transmission customers 19 themselves, the municipal electrical utilities and the 20 direct customers. The conversation between those 21 parties haven't really taken place. 22 MS LITT: All right. Would you flip to 23 Exhibit B, tab 4, schedule 1, page 21. I am looking at 24 lines 22 to 24. 25 The rationale for rejecting options 1, 9 and 26 10 was that they are based on an arbitrary 27 classification of customers. Is that classification a 28 of customers the definition that is proposed under tab 3 65 1 or was it a different definition? 2 MR. PORAY: I think what we were referring to 3 here was the existence of the power district which would 4 not be a going forward position and therefore that was 5 really the basis of eliminating those options. 6 MS LITT: Is there a reference in the evidence 7 to the distinction drawn between the power district and 8 the proposed definition of transmission customers? 9 MR. PORAY: I think we defined the power 10 district in -- yes, on page -- on Exhibit B, tab 4, 11 schedule 1, page 15. 12 The difference would be that you would be 13 separating within -- from the power district you will be 14 separating the direct customers, Ontario Hydro's 15 distribution company and then, of course, you would then 16 have also a local distribution company. 17 MR. MIKHAIL: I think the point is -- one is 18 characterized as arbitrary and then we drop two options 19 because they are arbitrary so you kept the status quo, 20 that is arbitrary in terms of long term, and you drop 21 two options because they are characterized as arbitrary. 22 That is the point, I think, was being made and what 23 direction --- 24 MR. PORAY: Well, I think long term, we have 25 indicated that we would go to the proposal that only 26 those customers who are connected to the transmission 27 system are transmission customers but in order to get 28 there, there is some work that still needs to be done 66 1 and what we proposed in the interim period is to go with 2 three groups of customers and call them transmission 3 customers. 4 MR. MIKHAIL: I am not going to debate. I am 5 just saying this is the point. 6 MR. CURTIS: Maybe to try and help out a 7 little bit in this is that the reference that was made 8 in terms of why those three options were dropped was 9 around the definition of customer within a power 10 district model or power district paradigm. 11 As we went through our stakeholdering process, 12 we felt that we got general agreement amongst 13 stakeholders that we couldn't go forward in the 14 unbundling and the creation of the new electricity 15 industry with a concept like power district. 16 So what we are saying is that in terms of 17 these three options, since it was based on the power 18 district and that there was general support for dropping 19 the power district definition, that those particular 20 options should be dropped. 21 We are also talking in terms of another 22 definition of transmission customers and this the 23 historical definition of what a transmission customer 24 is. 25 As Andy explained earlier, the conversations 26 that are required amongst the municipal electric 27 utilities, ourselves and the direct customers, have not 28 taken place on whether or not -- on how to change that 67 1 definition of a transmission customer. 2 So from a historical concept, it may seem that 3 that definition is more arbitrary than just saying a 4 transmission customer is anybody that is directly 5 connected to a transmission customer but within the 6 context of this, we did not feel that we had the 7 sanction from all of the industry players to drop that 8 definition. 9 MR. MIKHAIL: All right, that is fine. Thank 10 you very much. I think if there is any point that we 11 need to clarify, we can come up with an interrogatory on 12 that but that is fine. 13 We are going to move to the area of charge 14 determinants and related aspects. 15 The first area that I want to touch on is on 16 fixed and minimum charges. I have one clarification and 17 two questions. 18 The clarification is referenced in Exhibit B, 19 tab 5, schedule 1. 20 MR. CURTIS: Sorry, B or D? 21 MR. PORAY: Sorry, what was --- 22 MR. MIKHAIL: No, "B" like Bob. 23 This is the stakeholdering --- 24 MR. CURTIS: I am sorry, can you give us 25 the -- tab 5? 26 MR. MIKHAIL: I am at lines 20 to 23. It was 27 referenced or --- 28 MR. PORAY: Can you just hang on for a second. 68 1 We need to try and catch up with you. 2 MR. MIKHAIL: All right. 3 MR. CURTIS: Tab B? 4 MR. MIKHAIL: Exhibit B, tab 5. 5 MR. CURTIS: Right. And where --- 6 MR. MIKHAIL: Schedule 1. 7 MR. CURTIS: What page, sorry? What was the 8 page again, sorry? 9 MR. MIKHAIL: Hang on a second. It is 10 actually referenced to in Exhibit D as well and so if 11 you want to go there and refer from there -- you can 12 refer also to Exhibit D, tab 4, schedule 1, page 7, 13 lines 5 to 7 and then 18 to 24, and in it they reference 14 Exhibit B, the stakeholdering reference. 15 My point is, and I want to just clarify 16 that --- 17 MR. ROGERS: Could you just give us a moment, 18 please, so we can make sure that we understand your 19 question? 20 MR. MIKHAIL: Okay. 21 MR. ROGERS: Okay? 22 MR. MIKHAIL: Okay. Basically, the reference 23 in the stakeholdering Exhibit B talks about six charges. 24 There is no explicit reference to anything else. Like, 25 when you talk in Exhibit D, you talk about minimum 26 charges and fixed charges synonymously but when you 27 refer to the reference in the stakeholdering, they 28 really talk about fixed charges. There is some subtle 69 1 difference between the two. 2 Would you concur that there is some subtle 3 difference between the two? 4 MR. CURTIS: Between a fixed charge and a 5 minimum charge? 6 MR. MIKHAIL: Yes. Like one is a subset or 7 another and not necessarily meaning the same thing. 8 MR. CURTIS: I think what we were talking 9 about in terms of fixed charges is the aspect of the 10 charge determinant that we were discussing in terms of, 11 for example, charges against the infrastructure so those 12 would be considered to be fixed charges. 13 But what you are raising is sort of going 14 beyond that notion of imposing a minimum charge. 15 Is that --- 16 MR. MIKHAIL: That is right, which would be a 17 subset of the whole sort of structure, right? 18 That leads to my question and my question is 19 referenced, as I mentioned before, in Exhibit B, tab 4, 20 schedule 1. 21 There was reference to a suggestion that you 22 look into it, right, and my question is, has anyone 23 looked into it quantitatively, done some analysis on it? 24 MR. CURTIS: The concept of a minimum charge? 25 MR. MIKHAIL: That is correct. 26 MR. PORAY: Well, I think our reasoning for 27 why we dropped those is stated in 4.3. 28 MR. MIKHAIL: Yes, and this is leading to my 70 1 next question. 2 Without doing quantitative analysis, can one 3 make a conclusion that said and acceptable are not -- 4 when you make a conclusion saying "fair or acceptable 5 charges are not acceptable" in lines 15 and 16, can one 6 do that without looking at the numbers in a construct 7 and do some analysis, you know, you make two references 8 to it. 9 MR. MIKHAIL: In one you say minimum charges 10 may be devastating for some customers. It is sort of a 11 strong statement. 12 Without analysis, how can one reach that 13 conclusion? 14 MR. PORAY: I think what our assessment is 15 based on is that we did look at a number of examples of 16 customers ranging in size and that led us to this 17 conclusion. 18 MR. MIKHAIL: But did you have a level for 19 that minimum charge to see if that is going to be 20 devastating and not acceptable? I don't want to 21 belittle this morning, but like my point is, I think 22 there was a conclusion and there wasn't any quantitative 23 way to measure it, whether from a pricing structure or a 24 rate structure and some pattern of customer usage that 25 you think those kinds of customers that would be 26 affected badly or -- 27 MR. CURTIS: I think in this particular area, 28 what we were noticing is that for some of the smaller 71 1 customers, if there was this fixed or minimum charge 2 imposed upon them, that they would be looking at rates 3 that were multiples of what they would be currently 4 paying and that was sufficient for us to conclude that 5 it would end up being unfair for certain customers. 6 MR. MIKHAIL: So there was a rate structure 7 that you came up with, with a proposal to get a portion 8 of your system elements identified and a minimum charge 9 designed around it? Was that done, or was it done just 10 quantitatively? 11 MR. CURTIS: I think it was probably 12 semi-quantitatively. It wasn't that we actually sat 13 down and designed a specific structure and looked at 14 what the implications would be for individual customers. 15 It was looking at individual customers and sort of what 16 their current status is or what they currently would be 17 paying, and what the implications would be for imposing 18 a fixed charge upon them, and it was fairly obvious, I 19 think, to us that we were talking about charges 20 increasing many times. 21 We are not talking about a few percent here, 22 we are talking about several times, and so based on that 23 we concluded that. 24 MR. MIKHAIL: Okay. I guess we can sort of 25 cover that with an interrogatory and get some numbers, 26 get some sort of more detailed analysis on that. 27 MR. CURTIS: Yes, I would just caution, 28 though, that I think what we did was we looked at 72 1 specific customers and customer data, and I think we are 2 very conscious of the commercial nature of the 3 information that we have on customers and I don't 4 believe that we would be able to respond to any 5 interrogatory that asked us to reveal data or 6 information on specific or individual customers. 7 MR. MIKHAIL: No, that is fair enough, you can 8 always hide it and characterize saying low load factor, 9 high load factor, medium load factor. You don't have 10 to -- 11 MR. CURTIS: Okay. 12 MR. MIKHAIL: -- give us information we 13 shouldn't have. 14 MR. CURTIS: All right. 15 MS LITT: I have some questions on charge 16 determinants and it relates to Schedules 2, 3 and 4 of 17 Exhibit D, Tab 4. 18 On Schedule 2, where the various types are 19 identified, I compared type C and type L and couldn't 20 see tremendous differences between the two quantitative 21 results. Similarly, type C, type D and type K, I 22 couldn't decern the similarities. 23 Was there a reason to apply types which were 24 convergent in a sense? 25 MR. PORAY: I think our perspective was, when 26 we were looking at these different types, was to try and 27 evaluate a range of options, some of which were proposed 28 by stakeholders, so in included a variety. 73 1 MS LITT: I tried to link the results on each 2 of the pages back to a specific site. I don't know if 3 this information will be at your fingertips today or 4 not, but for five of the different pages I couldn't link 5 them back to a specific type -- page 10, for example. 6 MR. PORAY: Page 10 of Schedule 3? 7 MS LITT: No, of Schedule 4. 8 MR. PORAY: Schedule 4 -- I am 9 sorry -- page 10. 10 MS LITT: The two columns that gave me most 11 difficulty were "total annual transformation connection 12 charges" and "total annual line connection charges". 13 Can you refer me to a type that forms one of 14 the inputs to determining those charges? 15 MR. PORAY: What you are looking here is each 16 of those tables, 1 through to 18, summarizes the 17 combination options. Okay? 18 MS LITT: Okay. 19 MR. PORAY: So what we have taken is the types 20 and applied one type to connection, line connection, and 21 one to transformation connection and one to network. 22 This is a summary of all that. 23 So for option 9, which is revenue by group, 24 monthly coincident peak, we indicate the network charge, 25 the line charge, and the transformation rate and then we 26 would apply -- that is the summary of that. 27 MS LITT: Okay. Give me an example. 28 MR. PORAY: And if you go back to the type -- 74 1 MS LITT: Yes, that is what I would like to be 2 able to get. 3 MR. PORAY: Okay. So it would be Type B, 4 monthly coincident peak. 5 MS LITT: And that gives the rate -- or I can 6 verify the numbers in total annual network charges 7 against Type B, but I can't apply Type B to determine 8 the connection, transformation connection or line 9 connection. 10 Those two columns were the difficult ones for 11 me. 12 MR. PORAY: Okay, let's see. What was done 13 there is that the revenues were allocated to the groups 14 by monthly coincident peak. And then the customer 15 charges were based on the monthly peak within the peak 16 period. 17 So if you look at page 3 of Tab 4, Schedule 3, 18 this is a table which shows the combination of options 19 for the charge determinants. 20 MS LITT: Yes. 21 MR. PORAY: And if you go down mid-way that 22 page, you will have option or combination Option 9. 23 MS LITT: Yes. 24 MR. PORAY: It says, revenues allocated by 25 groups, by monthly coincident peak and then the charges 26 are based on Option 2, which is monthly peak during peak 27 period from network and monthly non-occurrences and peak 28 for line and transformation connection. 75 1 MS LITT: And where could I pick up those 2 percentage splits? Is that buried in Type B? 3 MR. PORAY: Well, the revenues for the line 4 connection, transformation connection and network 5 connection are available at the end of Tab C -- sorry, 6 Exhibit C. 7 MS LITT: Yes. 8 MR. PORAY: If you go to Exhibit C, Tab 8, 9 Schedule 1, page 2. 10 MS LITT: Yes. 11 MR. PORAY: Okay. So you have the revenues 12 there on the pool basis. 13 MS LITT: Good. 14 MR. PORAY: And then you can take those, 15 assign them to the groups so this would be the direct, 16 the local distribution companies based on the monthly 17 occurrences and peak of those groups. 18 MS LITT: Okay. I will track that through. 19 Thank you. 20 MR. MIKHAIL: Can we move to the next topic? 21 MR. RODGER: Certainly we can. 22 MR. MIKHAIL: The next one would be the net 23 versus gross. 24 I believe the first one Kathi did that -- 25 enquire about the generation efficiency as an 26 objective -- so we skip that one. 27 The next one is about forecasting. And it's a 28 clarification. 76 1 The reference is Exhibit D, Tab 5, Schedule 1, 2 page 19, starting at line 24. And the clarification is: 3 Has OHNC considered how a forecast of new and better 4 duration would vary with regard to the transmission 5 pricing, the two options, net load billing versus gross? 6 Have you looked at the forecast of that embedded 7 generation under these two? There was no forecast, to 8 my knowledge, of net potential under the two different 9 regimes. 10 MR. PORAY: I think the assumptions that were 11 made in forecasting the new generation -- and this work 12 was done for us by a consultant -- was, essentially, 13 looking at the gas prices and their interpretation how 14 the market will evolve in Ontario. I don't believe that 15 they took into evaluation the fact of transmission 16 charges. 17 MR. MIKHAIL: Is that possible to have that 18 done? 19 MR. CURTIS: I think, probably, in terms of 20 how these evaluations are done, when you look at how you 21 go about doing these evaluations, you look at the energy 22 price, the commodity price component, and that's going 23 to make up something in the order of at least 60 to 80 24 per cent of what the total costs are that are faced by 25 new generators coming onto the system. And I think what 26 you are asking for is the remaining, say something in 27 the order of 15 per cent of the costs to look at a 28 variant, you know, around that, and I think when we were 77 1 talking with our consultants around that, that was sort 2 of getting beyond the scope of what could be done, in 3 terms of generating a forecast. Basically, you are 4 talking about an incremental change on an incremental 5 component of the total costs that were basically 6 incurred by these generators coming onto the system. 7 The other aspect, too, is that we have offered 8 up our own study, but you probably are also aware that, 9 through our stakeholder process, a number of other 10 stakeholders had undertaken to provide forecasts of how 11 much new generation could come on the system. And I 12 think if you do those comparison, you will see they are 13 remarkably consistent, in terms of the amount that's 14 forecasted. So I think, overall, you know, what you are 15 asking for, in terms of the variation around net versus 16 gross load pricing would make a relatively small 17 incremental change, in terms of what the forecasts would 18 be. 19 MR. MIKHAIL: Okay. The next question is also 20 forecast, but it's of a different nature. 21 Has OHNC undertaken to see the percentage of 22 load appearing on the network of load supplied by 23 embedded generations? Diversity comes to play into 24 that. Have you tried to estimate the amount that really 25 appears on your network from those generators that you 26 forecasted -- like you forecasted, from 2002 to 2008, 27 the portion that appears on the network of those loads 28 supplied by the embedded generation; and diversity comes 78 1 into it, of course -- just to see the portion of the 2 loads that appears on the network to reflect usage by 3 those loads that would be supplied by embedded 4 generations? 5 Have I made myself clear? 6 MR. PORAY: The impact of the load forecast is 7 included. 8 MR. MIKHAIL: The impact of the load 9 forecast -- no, I am -- 10 MR. PORAY: But this is the forecast of loads 11 of the municipal electrical utilities and the direct 12 customers. 13 MR. MIKHAIL: No, this is not what I am 14 asking. 15 What I am asking is, like, they are 16 forecasting a certain amount of loads that will be 17 supplied by embedded generation. In that load, that 18 load would reflect differently on your various stages of 19 your system. When you come to the common network, you 20 have a different amount than at the regional lines 21 supplying them, for example, so you have different 22 levels of that load. And because of diversity, you 23 know, not all generators are going to be down at the 24 same time, you have that kind of diversity and 25 randomness to it. And you can ask the consultant to do 26 it for you or have someone do it or -- like however. 27 MR. PORAY: I think the basis of our work was 28 that -- we assumed that these generators are affected, 79 1 base load -- that there is some allowance made for 2 outages, and that's how we measured the -- that's the 3 account that we took off those generators coming on. 4 MR. MIKHAIL: Okay. I'm not going to take 5 that any further. I think we can follow that with an 6 interrogatory at the right time. Let's leave it that 7 way. 8 Kathi, do you want to take over the exports 9 and...? 10 MS LITT: Can you turn up Exhibit D, Tab 6, 11 please. 12 There's a reference made, on page 11 I think 13 it is, level of charges comparable to the average 14 point-to-point transmission service and surrounding 15 utilities. 16 Can you name some of those surrounding 17 utilities, please? 18 MR. PORAY: Yes. I think we have compared to 19 New England Power, PJM, New York -- I think those 20 were -- I think Michigan, as well. 21 MS LITT: And do they have the same levelized 22 unit charge? Or do they use different rate design 23 constructs? Hawkinson's rate? Anything else? 24 MR. PORAY: Basically, it's very similar. 25 They, under the FERC proposals, or under the FERC 26 filings, there are what's called "point-to-point 27 transmission", which is a postage stamp rate which the 28 utilities can discount from to provide transmission for 80 1 out and through type transactions. 2 MS LITT: That postage stamp rate, is that 3 charged on a unit of energy, similar to the way that 4 this wheel through charge -- 5 MR. PORAY: -- for wheeling through, yes. 6 MS LITT: Does the proposed tariff that this 7 charge would be levied under conform with all the 8 requirements of the FERC or any other tribunals or any 9 trade bodies? 10 MR. PORAY: We don't see any reason why this 11 would not be acceptable to FERC or other bodies. 12 MS LITT: Are there any considerations under 13 NAFTA that need to be accommodated in the tariff or the 14 rate structure? 15 MR. CURTIS: It was brought up during our 16 stakeholding process that it could potentially be a 17 concern. 18 We have, I think, consulted internally with 19 our lawyers and the problem with this is just about 20 anything could be addressed under a NAFTA challenge and 21 you probably -- and although we have looked at it and 22 our lawyers have look at it and we don't feel that this 23 gives any grounds for a NAFTA challenge, that doesn't 24 doesn't necessarily -- that doesn't preclude that that 25 might not happen and it also doesn't preclude that the 26 decision might go against us as far as NAFTA is 27 concerned. 28 But, the best of our knowledge at the moment 81 1 is that there isn't anything in what we are proposing 2 that, you know, should represent a challenge as far as 3 NAFTA is concerned, under NAFTA. 4 MS LITT: Can you point me to somewhere in the 5 evidence that a forecast of the volumes that will be 6 transacted under this wheel-through rate is set out? 7 MR. PORAY: No. We didn't -- it is not 8 possible for us to determine what volume of transactions 9 will take place. 10 MS LITT: Is there a regulatory mechanism that 11 is proposed to capture the revenues that will arise from 12 these transactions as they occur? 13 MR. CURTIS: A regulatory mechanism? Like a 14 holding accountnt or -- 15 MS LITT: Yes. 16 MR. CURTIS: I think that is basically the 17 mechanism that we are envisaging as far as this is 18 concerned, is that it would be held in an account and 19 then it would be available for distribution back to 20 customers in terms of lower transmission charges in 21 subsequent years. 22 MS LITT: Is that set out in the evidence? 23 MR. CURTIS: I don't know whether we got that 24 far in terms of -- I think one of the dilemmas in terms 25 of what we have presented here is in terms of how much 26 we got into implementation mechanisms. But that was the 27 concept. 28 I think we did explain that this collection 82 1 would be attributed back to transmission customers. 2 MS LITT: Could you turn to page 2 of that tab 3 please? My question concerns lines 5 through 7. The 4 reference made to transaction charges. Are those the 5 costs to actually facilitate the transactions? 6 MR. PORAY: These would be the costs that 7 would be charged by the independent market operator in 8 handling those transactions, yes. 9 MS LITT: Have those costs been quantified? 10 MR. PORAY: To my knowledge, they haven't. 11 They would depend on the operating conditions of the 12 system at the time the transaction was taking place. 13 Some of that will include congestion costs and 14 incremental losses. 15 MS LITT: Is there any where I could find a 16 list of those costs? 17 MR. PORAY: If there is a place where you 18 could look, it would be with the IMO. I am not aware of 19 those costs actually being listed and identified. 20 MS LITT: Thank you. 21 MR. MIKHAIL: Can we move to see an exhibit in 22 tab 7? The very lengthy tab 7. I have two questions 23 there. It is really a clarification for our knowledge 24 because we have all different concepts of what different 25 things mean. So, I am going to go through them and you 26 can tell me what is your thinking on it. 27 So, the first one is on that schedule 1 and it 28 is page 1, lines 23 to 27 and in page 2, line 1. Three 83 1 things I need to clarify. What is exactly meant by 2 keeping the pool whole? 3 This is regarding investments, of course, and 4 so on. So, when you are investing and you want to keep 5 the pool whole, how exactly do you do that? Or what is 6 meant, first, by keeping the pool whole in terms of 7 detail, not -- the concept is very good. I understand 8 it. But, how do you measure that? 9 MR. PORAY: Well, I think, the way -- the 10 intent here is that the new investment that would be 11 made, if it was added to the pool, it would increase the 12 pool costs and the rate to the existing pool customers. 13 MR. MIKHAIL: Okay. And you bring the notion 14 of capital contribution -- 15 MR. PORAY: Yes. 16 MR. MIKHAIL: -- to sort of pump it up so you 17 keep the pool whole, right? 18 MR. PORAY: Yes. 19 MR. MIKHAIL: Okay, and do you do that through 20 some model, looking at revenues over certain horizon and 21 so on? Can you give us the details of that if we ask 22 for it? We can follow up with an interrogatory on that 23 and give us the model -- the parameters of the model. 24 How do you propose to do it? 25 MR. CURTIS: I think that there is a general 26 model that we follow and that we have followed 27 historically and it is based on the revenue stream that 28 one would expect out of the new connection facility and 84 1 how -- 2 MR. MIKHAIL: And it is certain horizon you go 3 over and you have a certain discount rate but can you 4 give us the details on that if we follow up with an 5 interrogatory? 6 MR. CURTIS: I think we probably could. 7 MR. MIKHAIL: Good. Okay. 8 Okay. The second one -- the second question. 9 It is in page 5, lines 3 to 6, and there is a different 10 perspective on, I guess, the same thing but you refer to 11 it differently -- and I am going to quote: "To affect 12 this would require...". This is the sentence that I am 13 referring to. Basically what I am asking is exactly how 14 you accomplish this? 15 You mention that whether or not the load 16 connection costs more than the average of similar 17 investments and this didn't really jive with the 18 business of a model and discounting and so on. It is 19 just two different things, I think -- or maybe not. 20 MR. CURTIS: No, no. It is exactly -- 21 MR. MIKHAIL: Exactly the same thing? Through 22 the same model? 23 MR. CURTIS: Yes. 24 MR. MIKHAIL: So forget the model and the 25 details of exactly how you do the evaluations would be 26 able to clarify that? 27 MR. CURTIS: I believe so. 28 MR. MIKHAIL: Okay. 85 1 MR. CURTIS: Yes. 2 MR. MIKHAIL: Thanks. 3 Okay. We move to the next topic and it is 4 basically should generators -- that is tab 8. Should 5 generators pay for existing transmission connections? 6 I have one clarification -- two clarifications 7 and one question and I think you partially answered that 8 so if you did, just, you know, tell me and I will skip 9 it. 10 Basically, it is regarding charging generators 11 for existing connections; and I quote: 12 "In consideration of the matter of 13 assigning generators in Ontario a portion 14 of the existing transmission connection 15 costs, it should be noted that this is 16 not the normal practice and surrounding 17 jurisdictions." (As read) 18 And the clarification is can you mention which 19 jurisdictions those are and tell us about it or if you 20 don't have it in front of you, we can ask about it? 21 MR. PORAY: I don't have it at my fingertips 22 at this point. My memory is that in New York and PJM 23 and New England, this is not the norm to charge 24 generators for the existing connections. 25 MR. MIKHAIL: Okay. So, you mentioned New 26 York, New England and -- 27 MR. PORAY: PJM. 28 MR. MIKHAIL: And if you have more information 86 1 on this, more detailed information, we can ask about it? 2 A proper interrogatory will get it? 3 MR. PORAY: Yes. 4 MR. MIKHAIL: Okay. The second one mimicked 5 what Kathi was asking for about NAFTA, FERC and so on 6 and I think is the answer is the same about the same 7 issue there or, if not, can you elaborate about this? 8 MR. CURTIS: I think the answer is the same. 9 We have taken -- we have tried to take that into 10 consideration when we developed our position. 11 MR. MIKHAIL: Now, this one here is 12 hypothetical Mr. Dunloud(ph). 13 MR. DUNLOUD(ph): In your case, it is. We are 14 going to make an exception. 15 MR. MIKHAIL: Okay. Thanks. 16 --- Laughter 17 How would you go about first establishing what 18 is an upgrade associated with a generator? 19 MR. MIKHAIL: How would you go about first 20 establishing what is an upgrade that is achieved a new 21 generator coming in on a radial line that has customers 22 and generators existing? 23 How do you go about finding exactly the 24 amounts that are attributable to this guy and how do you 25 do that on an ongoing basis, establish a new pool for 26 new generators that requires some upgrades or you deal 27 with it on a sort of piecemeal basis or how do you 28 foresee that? 87 1 MR. CURTIS: Can we understand your 2 hypothetical example of -- we are adding a new 3 generator --- 4 MR. MIKHAIL: Well, at least connecting to the 5 system. 6 MR. CURTIS: --- to an existing --- 7 MR. MIKHAIL: Yes. He is going to connect to 8 your existing radial system, has a lot of generators 9 existing, and a lot of loads, and you may have one or 10 more coming in the future. 11 MR. CURTIS: Right. 12 MR. MIKHAIL: How do you go about -- you know, 13 you can get the captive component of any upgrade that 14 you do and maybe charge them upfront or something 15 because you are not having any revenue from these 16 people. 17 MR. CURTIS: And I guess just for my 18 clarification, what part of this are you considering to 19 be the upgrade? Are you --- 20 MR. MIKHAIL: On the line connection. 21 MR. CURTIS: On the existing --- 22 MR. MIKHAIL: On some radial line, 115 kV, for 23 example. 24 MR. CURTIS: Okay. But I guess what I am 25 having a little problem with is that you are clear that 26 this new generator, when he attaches to the existing 27 radial line, pays for that portion of the new connection 28 automatically under our proposal. 88 1 MR. MIKHAIL: Yes, right. And then --- 2 MR. CURTIS: And then what you are talking 3 about is then what if we have to do an upgrade to that 4 radial connection going back from his new connection 5 point. Is that --- 6 MR. MIKHAIL: Yes, and sometimes possibly 7 right into the network. But let's sort of limit it to 8 the line connection, to the radial line. 9 What happens to the portion of owing and a 10 cost, operation and maintenance costs ongoing, its 11 contribution to that? How do you go about doing that? 12 Do you have a sub pool for these people or how do you go 13 about tracking the costs, ongoing costs? 14 It is not very clear in my mind, you know, 15 reading the evidence, how you do that. 16 MR. PORAY: I think our understanding is that 17 to the extent practical, you would identify the 18 beneficiaries of that upgrade and you would charge those 19 beneficiaries. So if it is that generator that is 20 benefiting mainly from that, then those additional 21 charges of the upgrade and the RMA would be assigned to 22 him or her. 23 MR. MIKHAIL: So your present works, all the 24 future RMA, have it up front or have him pay on an 25 annual basis or how do you go about doing that? 26 MR. CURTIS: I think that particular portion 27 of it is still fairly open because obviously, at least 28 from our perspective, what would happen is that you 89 1 would have to enter into a contractual negotiation with 2 that new generator. That new generator may wish to pay 3 all of those charges up front in one lump sum, and if 4 so, yes, that generator may wish to pay for it over some 5 period of time, and from our perspective, we would make 6 that option available to the generator as well. 7 There may be other financing options that the 8 I don't think we could talk about now, maybe we don't 9 know about them but we would be fairly open in terms of 10 how that would get paid for. 11 MR. MIKHAIL: Okay, that is fair enough, 12 thanks. That covers that one. 13 MS LITT: By my reckoning we are at the lunch 14 break, so if we could break and come back at about 1:30, 15 please, and we will continue with Exhibit D, tab 9. 16 --- Upon recessing at 1128 17 --- Upon resuming at 1330 18 MR. THIESSEN: All right. Why don't we get 19 started for the afternoon part of our session. I 20 understand that Board staff still have some questions 21 and I have a couple of them. 22 I am going to go to Exhibit D, tab 9, which is 23 the low voltage shared facilities chapter. You indicate 24 in this chapter that you think that this issue should 25 resolve in a different forum. You mentioned the 26 distribution side of cross-allocation and rate design. 27 I'm wondering what the relation is between this issue 28 and the effect on the revenue requirements on the 90 1 transmission side and if there's an overlap there. 2 MR. PORAY: Our understanding is that the 3 local did share facilities. The revenues associated 4 with those are part of the distribution fight, not the 5 transmission. 6 MR. THIESSEN: I see. So then my question 7 would be why was it brought up in the first place in the 8 consultation and in this evidence? There is no relation 9 to the transmission side. 10 MR. PORAY: I think that the guidance that we 11 had was that in the OED rate order of April 15 there was 12 an item in there to address all these facilities. 13 That's why we embarked on it with the stakeholders. 14 MR. THIESSEN: But then pulled it out. 15 MR. PORAY: Yes. 16 MR. THIESSEN: Okay. That's my only question, 17 I think. I think Kathi has some further questions. 18 MS LITT: Would you turn to Exhibit D, tab 10, 19 please, locational transmission pricing. At what point 20 does OHNC contemplate implementing locational 21 transmission pricing, if at all? 22 MR. PORAY: We view this as a potential part 23 in the future. 24 MS LITT: Is there a point in the future when 25 it might be implemented though or some variation on 26 locational transmission or locational marginal price? 27 MR. PORAY: I think our starting position was 28 really the direction which was given to us, which was 91 1 given in the government White Paper in terms of uniform 2 pricing to our customers across the province. The 3 indication we have is that this is still the government 4 policy. 5 One could look at locational transmission 6 pricing and the timing of locational transmission 7 pricing to potentially come in or factor in maybe when 8 locational marginal pricing comes into being in the 9 marketplace, in other words, moving more towards cost 10 causality. 11 The current timetable for locational marginal 12 pricing is potentially 18 months after the market opens. 13 MS LITT: Okay. Given that it's that far in 14 the future, why was the issue -- why was this filing 15 made at this time? 16 MR. CURTIS: When we were doing the 17 stakeholdering consultation, some of the stakeholders 18 raised this as an option that they wanted, that they 19 thought should be examined. 20 MS LITT: Are there any jurisdictions which 21 are using transmissional transmission presently? 22 MR. PORAY: Our understanding is that in 23 Australia this is used partially for pricing 24 transmission. It's used in combination with postage 25 stamps. 26 MS LITT: No neighbouring jurisdictions are 27 applying it. 28 MR. PORAY: No neighbouring jurisdictions, no. 92 1 MS LITT: Thank you. Could you turn to tab 2 11, please. On page 1 of Schedule 1 there are eight 3 different pricing options set out. All of those and the 4 contracts that they gave rise to are continuing until 5 the market opens. Is that correct? 6 MR. PORAY: Until the market rules are 7 proclaimed, yes. 8 MS LITT: And that will be when, do you think? 9 MR. PORAY: I think the target date is 10 November 1, 2000. 11 MS LITT: Okay. And after November 1, is it 12 OHNC's proposal to have any of these survive -- all of 13 these survive, none of them survive? 14 MR. PORAY: OHNC's proposal is none of them 15 should survive. 16 MS LITT: Okay. None of the existing 17 contracts would survive, but would any of the pricing 18 provisions that are described in the list, would any of 19 those be offered? 20 MR. PORAY: These pricing provisions deal 21 really with the energy component. It's not part of our 22 responsibility. 23 MS LITT: Okay. With respect to back-up 24 service, the contracts that are in force today would be 25 null and void on the market opening, but would there be 26 some back-up service provided? 27 MR. PORAY: I think it would be provided 28 really as part of the firm transmission service 93 1 automatically. 2 MS LITT: It would be bundled in with other 3 aspects like the transmission service. 4 MR. PORAY: Yes. 5 MS LITT: Okay. And who's responsibility 6 would that be? Would that be an OHNC responsibility or 7 an RMO responsibility or another body or do you know at 8 this stage? 9 MR. PORAY: I think it's possibly a share of 10 the accountability between the IMO and the OHSC -- OHNC, 11 sorry. 12 MS LITT: Has there been any consideration of 13 providing a transition mechanism from the specific 14 contractual obligations on to something else upon market 15 opening so that the customers see seamless service? 16 MR. PORAY: I'm not aware of any. 17 MS LITT: Thank you. 18 MR. THIESSEN: That's it for Board staff 19 questions. We can open up to the rest of the 20 intervenors. 21 MR. STEPHENSON: No questions. 22 MR. MEIGHEN: No questions. 23 MR. CAMPBELL: Gentlemen, I wasn't clear in 24 your answer to Ms Litt's question as to whether you were 25 saying there was or was not going to be a back-up rate. 26 MR. CURTIS: There isn't going to be a 27 specific back-up rate. 28 MR. CAMPBELL: So if somebody wants back-up, 94 1 as I understand your proposal, it's just they will buy 2 off the normal tariff. 3 MR. CURTIS: Well, in terms of what happens 4 under the circumstances. Everybody becomes a primary 5 customer. So back-up is offered, you know, as part of 6 the prime rate service delivery. 7 MR. CAMPBELL: So the practical result of that 8 is that the cost of back-up will depend on the charge 9 determinant that you choose that's chosen in these 10 proceedings for the firm service. 11 MR. CURTIS: Yes. 12 MR. CAMPBELL: Have you done any analyses to 13 determine the appropriate level of charges to recover 14 the costs of having the network available to serve 15 customers installing embedded generation when their 16 generation is down? 17 MR. PORAY: All considerations are based 18 really on the existing infrastructure which was put in 19 place to serve the existing load so that there will be 20 capacity available to serve that load. 21 MR. CAMPBELL: I understand that, but my 22 question is whether you had done any work to determine 23 what the appropriate level of charges would be to 24 recover the costs of having that network available in 25 the circumstances that I described? 26 MR. PORAY: I think the answer to your 27 question is that we haven't done specific studies to 28 look at provision of backup because we feel that -- 95 1 going back to what I said before is that the existing 2 infrastructure and the cost associated with it are the 3 right level to recover from a load customer whose 4 generator goes down. 5 MR. CAMPBELL: Let me come at this slightly 6 differently. You agreed that it is a benefit to 7 customers to have the network available to provide 8 service to them if they have embedded generation and 9 that generation goes down. 10 MR. PORAY: Yes. 11 MR. CAMPBELL: I guess my question, then, is 12 what work have you done to quantify that benefit 13 because, obviously, if they are being given something 14 that has value, you ought to take into account what it 15 is costing you to provide that value to that customer 16 when you are dividing up the whole of the pie amongst 17 all of the customers. 18 How have you arrived at that figure? 19 MR. CURTIS: I think the assumption that we 20 are making in terms of what we have put forward here is 21 that the value that a customer gets in terms of backup 22 is equivalent to the cost of providing that with the 23 existing infrastructure. 24 Now, when you talk about an embedded 25 generator, you are talking about -- with the proposal 26 that we are putting forward, that on the network side, 27 that it would be a component that would be shifted and 28 distributed among other customers. 96 1 So, the issue comes up now in terms of by 2 having an embedded generator there, if that generator 3 goes out of service and then they have to draw back -- 4 draw from the system. 5 What they are, in effect, paying, then, is the 6 system charge for that one month. But, they are 7 implicitly getting a benefit for the other month where 8 they are in service but they have that provision or that 9 ability to draw backup from. 10 I guess, in effect, what has happened is that 11 under our proposal that 50 per cent of that benefit has 12 been reallocated to the other customers within the 13 system. 14 I mean, this is the issue of net versus gross 15 load, effectively. 16 MR. CAMPBELL: That's right. 17 I understand how you have arrived -- I 18 understand that you have set a charge that will apply in 19 those circumstances. My question is what analysis have 20 you done that shows you that it is the right amount for 21 that service? 22 MR. PORAY: I think our basis for that is the 23 prospect has been approved. 24 MR. CURTIS: For the value of the services. 25 MR. CAMPBELL: But, I mean, that is what we 26 are here to talk about is how the cost should be 27 allocated and what cost has been approved for the kind 28 of service that I have described. 97 1 MR. CURTIS: Well, the cost is implicit within 2 our approved revenue requirement. 3 MR. CAMPBELL: I understand that. 4 MR. CURTIS: In terms of formality. 5 MR. CAMPBELL: Now, we are talking about 6 dividing that. 7 MR. CURTIS: Yes. 8 MR. CAMPBELL: How do you know -- how have you 9 figured out how much of the pie is taken up or is 10 attributable to the kind of service that I have 11 described. 12 MR. CURTIS: Yes. 13 MR. CAMPBELL: I mean, if you haven't done 14 it -- 15 MR. CURTIS: Yes. 16 MR. CAMPBELL: -- fine. 17 MR. CURTIS: Okay. 18 MR. CAMPBELL: That is -- 19 MR. CURTIS: Well, we did -- 20 MR. CAMPBELL: With T-3, you've done it or you 21 haven't and that is really all I am asking. 22 MR. CURTIS: Okay. When we arrived at the 23 number that we put in here, we didn't do it through the 24 mechanism that you are describing. So, we didn't do 25 that analysis. 26 MR. CAMPBELL: So, not only -- you haven't 27 proposed it on -- so, the proposal does not have an 28 analytic base to it and you haven't done that kind of 98 1 analysis for the kind of cost that I am talking about. 2 MR. CURTIS: For the kind of cost you are 3 talking about, yes. 4 MR. CAMPBELL: Now, the next one really is the 5 same kind of question, just to give you a little hint. 6 MR. CURTIS: Will it have the same answer? 7 --- Laughter 8 MR. CAMPBELL: Well, we can maybe save a lot 9 of time if it does if you give it at the front instead 10 of at the end but -- the question is just this have you 11 done any analyses to determine the appropriate level of 12 charges to recover the cost of having the network 13 available to provide power quality support to customers 14 installing embedded generation? 15 MR. PORAY: No. 16 MR. CURTIS: No. 17 MR. CAMPBELL: You do agree, however, that the 18 network does provide those benefits to those customers 19 in that circumstance? 20 MR. CURTIS: Yes. 21 MR. CAMPBELL: And it has real value to them? 22 MR. CURTIS: Yes. 23 MR. CAMPBELL: Now, I want to turn, briefly, 24 to the topic of new connection facilities and you have 25 pointed out in your filing that they should be billed on 26 a net load basis. Do I have that right? 27 MR. CURTIS: I can give you the reference if 28 you -- for new connection facilities? 99 1 MR. CAMPBELL: For new connection facilities, 2 and why don't we look at Exhibit B, tab 5, schedule 1, 3 page 18, lines 17 and 18. 4 MR. CURTIS: Would you give us your line 5 numbers again? 6 MR. CAMPBELL: Page 18, lines 17 and 18, and 7 for the benefit of the transcript, it says: 8 "Thus transmission connection service 9 based on new connection facilities shall 10 be based on net load billing 11 notwithstanding any proposals in this 12 schedule." (As read) 13 MR. PORAY: I think that is an error. 14 MR. CAMPBELL: So we could expect that to be 15 dealt with in the errata next -- I take it should be 16 gross load? 17 MR. CURTIS: Yes. 18 MR. PORAY: Yes. 19 MR. CURTIS: Yes, it should be gross. 20 MR. CAMPBELL: Okay. 21 Now, just on the opposite page there, page 19 22 of tab 5, Exhibit D, schedule 1, you indicated that your 23 studies around these matters extended for the years 2000 24 to 2008. Do you see that at line 5? 25 MR. CURTIS: Yes. 26 MR. CAMPBELL: Would we be correct though that 27 the impacts of any investment in embedded generation by 28 existing customers would persist beyond 2008? 100 1 MR. CURTIS: Yes, they would. 2 MR. CAMPBELL: I have got a couple of 3 questions about your contract-based approach to 4 transmission rates, and I guess the first one is what 5 specific activities you are proposing to undertake to 6 implement the long-term proposal for such a 7 contract-based approach to transmission rates? 8 MR. CURTIS: Do you have a reference for this? 9 MR. CAMPBELL: Yes, if you stick at the same 10 tab of Exhibit B, tab 5, schedule 1, page 36. I think 11 if you look then at lines 12 to 14 -- on line 12 through 12 to the end of line 14 on page 37, there is a discussion 13 of these long-term considerations. 14 MR. CURTIS: Yes. 15 MR. PORAY: We saw that this is a potential 16 way to deal with these issues in the future but we have 17 not thought through the implementations of these types 18 of contracts. 19 MR. CAMPBELL: So you don't have any 20 implementation plan even to work toward that proposal? 21 MR. PORAY: Yes. 22 MR. CAMPBELL: Have you done any thinking 23 about how customer classes would be created to implement 24 that type of approach? 25 MR. CURTIS: These discussions came about in 26 terms of discussions that went on within our advisory 27 part of the stakeholdering process and there really 28 hasn't been any development past that. 101 1 MR. CAMPBELL: Okay. If we can turn to the 2 last page of tab 5, schedule 1, Exhibit D, page 40. 3 The last sentence reads as follows -- and we 4 are talking about parity between end use customers 5 within the LDC -- it says: 6 "Such parity may be achieved by various 7 means, one of which is to bill the LDCs 8 on a gross load billing basis, a feature 9 used in some jurisdictions." (As read) 10 Is that what you are proposing? 11 The paragraph points out -- proposes that 12 consideration be given to it but is that in fact what 13 you are proposing or how are you dealing with it? 14 MR. PORAY: This is our suggestion that the 15 consideration would have to be part of the distribution 16 rate filing of the LDC -- 17 MR. CAMPBELL: I guess what we are not clear 18 about is whether the proposal is that LDC's be entirely 19 built on a gross load billing basis or whether the same 20 50 per cent feature of the balance of your proposals 21 also apply to the LDC. This would appear to say that 22 LDCs are going to be built entirely on a gross load 23 basis. 24 MR. PORAY: Yes. I think our proposal is to 25 do precisely that because the type of generation that 26 would be installed within the LDC territory would not be 27 the efficient type of generation that we were proposing 28 to net load bill on. 102 1 MR. CAMPBELL: Are you saying then that -- is 2 the deficient type of generation, they would get this -- 3 be dealt with on a different basis than the gross load 4 billing basis outlined at the reference I have given 5 you? 6 MR. PORAY: Our proposal is that the type of 7 generation that is installed within the LDC territory 8 should not be -- should not give an advantage to the 9 LDCs and therefore the LDCs would be billed on a gross 10 load basis. 11 MR. CAMPBELL: I have got some questions about 12 export transactions. 13 Just starting out, dealing first with the 14 situation with domestic customers, as I understand your 15 proposal, they would be charged both embedded costs of 16 the network and transaction costs through the IMO 17 uplift? 18 MR. PORAY: That is correct. 19 MR. CAMPBELL: And if I turn to -- I will give 20 you a reference for this. You can turn it up, as you 21 wish. 22 If I turn to page 3 of Exhibit B, tab 6, 23 schedule 1 -- and again, it is page 3 of that 24 schedule -- if I am reading lines 15 to 21 correctly, 25 the implication is that without infrastructure charges, 26 export transactions would only be paying one set of 27 charges, that is, transaction charges. Have I 28 understood that correctly? 103 1 MR. PORAY: Yes. 2 MR. CAMPBELL: Just to clarify then, export 3 transactions would however also be paying internal 4 uplift charges on the same basis as internal load. Do I 5 understand that correctly? 6 MR. PORAY: Yes. 7 MR. CAMPBELL: And export transactions would 8 also pay inter-tie congestion charges, in addition to 9 the internal uplift? 10 MR. CURTIS: If they existed, yes. 11 MR. CAMPBELL: And, based on your proposal, 12 export transactions would also pay a third 13 infrastructure or embedded cost charge which, I guess, 14 for ease of reference I will refer to as "the dollar a 15 megawatt hour". 16 MR. CURTIS: Yes, I think, in fact, that is 17 the only one that is in our proposal. The other ones 18 that you talked about, I think are part of the market 19 rules development. 20 MR. CAMPBELL: Yes, but they are charges that 21 export transactions would be subject to. 22 MR. PORAY: Yes, they are. 23 MR. CURTIS: Definitely. But we are not 24 proposing them here. 25 MR. CAMPBELL: Okay. I want to turn to a 26 question about charge determinants. Maybe I can do this 27 at a general level because we are not quite sure if we 28 understood this correctly. 104 1 As we understand the proposal, the sum of 2 forecast loads is measured at the delivery point across 3 the system that is divided into the revenue requirement 4 to get the rate. 5 Is that proposition correct? 6 MR. PORAY: What are you referring to? Can 7 you point us to -- 8 MR. CAMPBELL: Yes, well, we will take you 9 first then to Exhibit D, Tab 4 and if we can go to page, 10 I guess first to page 16, Schedule 1, page 16 behind Tab 11 4 of Exhibit D and down at lines 26 and 27, you say that 12 the detailed hourly load forecast was developed for each 13 delivery point of each transmission customer. 14 Do you see that? 15 MR. PORAY: Yes, I do. 16 MR. CAMPBELL: If we then go over to page 18, 17 you look at the first paragraph, which is lines 3 to 8 18 on page 18, you talk about at the end of that paragraph 19 that the rate for each of the pools is calculated by 20 dividing the revenue requirement by the corresponding 21 total volume of the charges determinants which the total 22 at the customer delivery point -- the total of the 23 customer delivery point load forecast. 24 MR. PORAY: For that pool, yes. 25 MR. CAMPBELL: Okay, there is a general 26 proposition then, it is the sum of the forecast loads as 27 measured at the delivery points across the system that 28 is divided into the revenue requirement to get the rate. 105 1 MR. PORAY: Yes. 2 MR. CAMPBELL: But then, as I understand your 3 proposal, the rate is applied to each customer according 4 to that customer's own non-coincident load. 5 Do I have that right? 6 MR. PORAY: On the connection charges, yes. 7 MR. CAMPBELL: How is it then that that won't 8 result in an over-collection, because it seems to me 9 inevitably that when you are taking a revenue 10 requirement, dividing it by a delivery point measured 11 load which would be a smaller number than the sum of the 12 individual customers non-coincident peak load, you have 13 divided a smaller number into the revenue requirement, 14 you are getting a rate and then you are multiplying that 15 in terms of gathering revenue by a number that is larger 16 than the customer load measured at the delivery point. 17 MR. PORAY: The revenues should be recovered 18 exactly. What we have done is we have identified for 19 each of the pools what are the megawatts of the 20 customer's through the delivery points which belong to 21 that pool. 22 Therefore, all those customers that are 23 charged because the take service from that pool would 24 recover the right amount of revenues allocated to that 25 pool. 26 MR. CAMPBELL: Right. In order to derive the 27 rate, are you dividing by the load as measured the 28 delivery point or as forecast at the delivery point? 106 1 MR. PORAY: Yes. 2 MR. CAMPBELL: But won't the sum of the 3 non-coincident loads, if you are looking at the 4 customers that are being charged, always be a higher 5 number? 6 MR. PORAY: The charge determined is the sum 7 of the non-coincident peak loads of the customers served 8 by that pool. Therefore, that should be correct. 9 MR. CAMPBELL: But it seems to me that the sum 10 of the non-coincident peak loads for the customer is 11 going to be a larger, in essence, a larger volume than 12 the measurement at the delivery point, not at the 13 customer, but at the delivery point of the measured load 14 at that spot. 15 --- Pause 16 I want to come back to this delivery point 17 definition for a moment. As I understand the 18 application, the delivery point is defined as an 19 OHNC-owned transformer station or a customer-owned 20 transformer station connected to the OHNC-owned 21 transmission line. 22 I can give you a reference for that, but I 23 think that is correct. 24 MR. PORAY: Yes. 25 MR. CAMPBELL: What, under that definition, is 26 the delivery point for an LDC that is supplied off the 27 distribution system of another LDC? 28 MR. CURTIS: Whatever the host utility is, 107 1 that is where the delivery point would be. 2 MR. CAMPBELL: How then do you determine the 3 appropriate charge to the one LDC for transmission when 4 what you are seeing is the supply to the host LDC? That 5 is very inelegantly asked, but do you understand, how 6 you get inside the nest? 7 MR. CURTIS: Yes. There is a charge that is 8 determined for transmission services delivered to the 9 host LDC and what we are, I think, recommending in terms 10 of our overall proposal here is that the same charge 11 determinant basis that the charge was made to the host 12 LDC be used in terms of charging not only within the 13 host LDC, but also the LDC that is served off that host. 14 Maybe a very simple-minded model here is that 15 if the charge at the host LDC is based on 100 megawatts 16 and you looked it and it was based at coincident peak, 17 for example, then that charge then would be prorated 18 between the host LDC and the embedded LDC based on 19 whatever the peak was at that time. That is probably 20 not a particularly good example but it is that 21 methodology that we are suggesting. 22 MR. CAMPBELL: In doing that calculation, are 23 you going to tie the charge to the embedded LDC share of 24 the host -- what shows up for the host LDC's 100 25 megawatts or are you going to look at the actual, I 26 guess, peak of the embedded LDC? 27 MR. CURTIS: Well, I think this is probably 28 beyond what we are -- is within our authority to do. 108 1 What we are going to do is we are going to meter it at 2 the host LDC and we will charge the host LDC based on 3 what that meter reading is. 4 The decision about how that gets allocated 5 between the host LDC and the embedded LDC is going to 6 have to be decided as part of the distribution hearing 7 process. 8 What we are suggesting is that the same 9 mechanism -- this would be our proposal to this is the 10 same mechanism that was used to calculate the charge at 11 the host LDC level should be applied throughout for the 12 host LDC and the embedded LDC. So if it was on a 13 coincident peak basis, then it is charged down through 14 to the embedded LDC on a coincident peak basis. 15 MR. CAMPBELL: At its coincident peak and that 16 is the embedded LDCs coincident peak. 17 MR. CURTIS: Well, yes, that is what our 18 recommendation would be but as I say, this is really 19 outside of our jurisdiction. There has to be 20 determined -- 21 MR. CAMPBELL: But isn't -- 22 MR. CURTIS: -- if there is a split within the 23 distribution hearing process. 24 MR. CAMPBELL: But isn't the embedded LDC a 25 transmission customer by your definition? 26 MR. PORAY: Yes, it is. 27 MR. CURTIS: Yes. 28 MR. CAMPBELL: If I can take you to Exhibit D, 109 1 tab 4, schedule 1, pages 9 and 10. If you go right to 2 the bottom of that, page 9, you point out that: 3 "If a customer fully owns or has fully 4 contributed toward costs of all of the 5 transformation or line connection assets 6 used to connect its delivery points to 7 the network, that customer would not 8 incur transformation or line, as 9 appropriate, connection pool charges." 10 (As read) 11 How do you propose to deal with customers who 12 have made a partial contribution? We have not seen 13 anything in the proposal, and we may have missed it, but 14 we have not seen anything in the proposal that outlines 15 a customer's partial -- how a customer's partial 16 contribution would be reflected in that customer's 17 rates. 18 MR. PORAY: Okay. The partial contribution 19 would not be in our asset data base so that cost would 20 not be included in our cost base. 21 If that customer made a contribution, a 22 partial contribution to a connection line but he is 23 still using the rest of that connection line to connect 24 to the system then he would be paid the pool rate. 25 MR. CAMPBELL: If I can take you to tab 12, 26 schedule 1, page 1, you indicate there that: 27 "The provisions of the transmission 28 services may be subject to change, 110 1 dependent on finalization of the 2 transmission system code and the Ontario 3 Market Rules." 4 Do you have any view as to any provision that 5 will likely be changed as a consequence of the work 6 being done on the transmission system code and market 7 rules? 8 MR. CURTIS: No. 9 MR. CAMPBELL: Do you expect that where -- 10 that if a conflict arose between the provisions approved 11 through this process and the transmission system code 12 and the market rules, that the provisions that are 13 approved through this process would have priority? How 14 do you see that working out? 15 MR. CURTIS: I don't think we know -- I 16 believe it would be the OEBs order that would take 17 precedence in this but if the market rules have to be 18 approved at a ministerial level, then they would take 19 precedence. 20 The transmission system code, as we 21 understand, would be approved through an OEB process so 22 I am not sure I know what the answer is, if you have got 23 one process that is approved by the OEB and another 24 process that is approved by the OEB and then a conflict, 25 how that resolution would be. 26 MR. CAMPBELL: Tab 13, again we are looking at 27 schedule 1 -- and I guess the question arises out of 28 commentary on page 2 -- you have indicated there that 111 1 the connection agreement included in the application is 2 preliminary for illustration purposes only and that the 3 terms and conditions cannot be finalized until all of 4 the regulatory instruments and codes are finalized. I 5 guess that is from page 1. 6 My question is what process you anticipate for 7 finalizing the connection agreement and whether you are 8 seeking approval from the Board of that agreement in 9 these proceedings. 10 MR. CURTIS: We think that the actual process 11 around arriving at connection agreements will have to 12 take place concurrently with the current proceeding but 13 would not be completed within the context of this 14 proceeding. So we are not looking that the current 15 would provide approval for the connection agreement. 16 MR. CAMPBELL: So it would be on a separate 17 but parallel track and you don't anticipate bringing 18 those tracks together in this proceeding? 19 MR. CURTIS: Not in this proceeding, no. 20 MR. CAMPBELL: Thank you. Those are my 21 questions. 22 MR. RODGER: Just one area and I think it 23 follows in part along Mr. Campbell's last questions. 24 If you stay with tab 13, and I just wanted to 25 read schedule 1, page 1 of lines 19 on, it reads: 26 "This application is aimed at seeking 27 approval for transmission cost, 28 allocation and rate design with the 112 1 supporting recommendations. 2 The Ontario Energy Board recognizes that 3 this approval is a prerequisite for open 4 access through the coming into force of 5 subsection 26(1) of the Electricity Act, 6 1998. This approval would also mark a 7 first step in the implementation of a 8 transmission tariff in Ontario. The 9 approved rates would become applicable in 10 customer connection agreement." 11 The Minister of Energy recently made a series 12 of announcements on the timelines for market opening and 13 the target date for 26(1) which is the 14 non-discriminatory access provision of the legislation, 15 coming into effect is November of the year 2000. 16 What then do you see as the timeline for this 17 first rate application. In other words, when do you see 18 it starting and when do you see it terminating? 19 MR. CURTIS: This cost allocation in rate 20 design proceeding, I guess, started on October 1st when 21 we filed as the OEB ordered us to do. We are expecting 22 that this proceeding would be concluded by some time in 23 the spring of next year and what we are talking about 24 here in terms of putting into place, for example, 25 connection agreement, would have to take place prior to 26 November of 2000. So there would be negotiations going 27 on at that point. 28 Having the Board order come out from this 113 1 particular proceeding would set what the transmission 2 rates would be and that would be one of the requirements 3 in terms of negotiating a connection agreement, knowing 4 what those are. 5 MR. RODGER: But I guess in terms of the first 6 rate order under this process, are we looking at 7 effectively an implementation date of November 2000, 8 assuming that is the target date, and then ending 9 December 31, 2000?. 10 MR. CURTIS: Yes. 11 MR. RODGER: And then there would be a new 12 process starting for 2001 rates. 13 MR. CURTIS: Yes. 14 MR. RODGER: And when would you see filing 15 those materials, the 2001 rates? 16 MR. CURTIS: I think we are anticipating that 17 it might be in the spring of 2000. 18 MR. RODGER: Really the long and short of it 19 is, at least under this process, we are really only 20 looking at possibly two months for an effective rate 21 order. 22 MR. CURTIS: Yes. 23 MR. RODGER: 2000 rates. 24 MR. CURTIS: Yes. 25 MR. RODGER: Thank you. A technical 26 conference is going to take longer than the rates are 27 going to be in effect. 28 MR. SNELSON: Ken Snelson for AMPCO. At the 114 1 risk of further confusing things, I had a follow-up 2 question to something that Bruce asked about 3 transmission delivery points. I have a follow-up 4 question about transmission delivery points. 5 The confusion was around places where there 6 were people identified as transmission customers who 7 were not directly connected to the transmission system 8 and that seemed to be the area of confusion. 9 MR. CURTIS: Yes. 10 MR. SMELSON: If you have a transformer 11 station which is feeding in the lower voltage network 12 connected to it, retail lows of the Ontario Hydro 13 distribution system, possibly an industrial customer who 14 is fed from 44 kV lines downstream and possibly an 15 embedded LDC that is less than 44 kV lines downstream of 16 that transformer station. 17 In your terminology, is that one transmission 18 delivery point or is that three transmission delivery 19 points? 20 MR. PORAY: In our terminology, that would be 21 one delivery point. 22 MR. SMELSON: Could you check that answer 23 because in previous discussions in the consultation I 24 got the other answer to that question, that it was 25 three. 26 MR. PORAY: Okay. I will check. 27 MR. SMELSON: Thank you. I have an area where 28 I believe there is an error. I don't think it's of any 115 1 intent to deceive or anything like that, but it perhaps 2 needs correcting. 3 If you turn to Exhibit D, tab 4, Schedule 3, 4 page 12. This diagram shows the impact direct 5 customers, LDCs and Ontario Hydro distribution customers 6 of five of the options for late determinant. For option 7 16 for the Ontario Hydro retail system, there is shown a 8 cost increase compared to option 2 of 6 per cent, of 9 nearly 6 per cent. You see the bar? 10 MR. PORAY: Yes. 11 MR. SNELSON: If you go back into the chart on 12 which that is based, then I believe it's Schedule 3, 13 table 6, on page 9 is where that number comes from. It 14 shows a 6 per cent increase for Ontario Hydro 15 distribution customers. 16 MR. CURTIS: Yes. Where are you? 17 MR. SNELSON: It's in the same schedule, but 18 on table 6 which is on page 9 of 13. That shows the 6 19 per cent number. That's where the 6 per cent comes from 20 in the previous graph. Right? 21 MR. CURTIS: Yes. 22 MR. SNELSON: If you go back to pages 6 and 7, 23 I believe those percentage differences are derived from 24 the numbers on pages 6 and 7. 25 MR. CURTIS: Yes. 26 MR. SNELSON: Then the impact of alternative 27 16, Ontario Hydro distribution customers, is 167 28 million. 116 1 MR. PORAY: That's the total revenue 2 recovered. 3 MR. SNELSON: Total revenue, yes. 4 MR. PORAY: Yes. 5 MR. SNELSON: And the impact of alternative 2, 6 which you are comparing against in that previous table 7 and figure, is 175. 8 MR. CURTIS: Yes. 9 MR. PORAY: Yes. 10 MR. SNELSON: And that is about 5 per cent 11 less than alternative 2 whereas the table and the figure 12 show it as being 6 per cent more. I believe there has 13 been a reverse in this find. 14 MR. PORAY: Yes. I will check that. 15 MR. SNELSON: Okay. Thank you. If you now 16 turn to Exhibit D, tab 4, Schedule 1, page 30. 17 MR. CURTIS: What was the page? 18 MR. SNELSON: Page 30. Exhibit D, tab 4, 19 Schedule 1, page 30. At the bottom of the page it lists 20 as a disadvantage of option 16 that this option has the 21 highest impact in terms of transmission charges on OHNC 22 distribution. 23 I believe with that correction you will want 24 to change those words to indicate that it has a lower 25 impact on OHNC distribution than your proposal 26 alternative which is alternative 18. 27 MR. CURTIS: Yes. We will do that checking. 28 MR. SNELSON: Thank you. Okay. Moving on to 117 1 another favourite subject, transmission customer 2 definition. Some of my questions were asked by Board 3 staff this morning. But I did want to be a bit more 4 specific than the Board staff. 5 We have heard that your definition of 6 transmission customer is the existing wholesale 7 customers of Ontario Hydro and that the reason for that 8 is that you haven't had time to do the work to determine 9 a structure that will fit with the new market structure. 10 If you turn to -- now, let's get this 11 right -- Exhibit D, tab 3, I believe page 4, you will 12 see that there are 15 -- there's a table in the middle 13 of that page -- there are 15 large users who are not 14 direct customers of Ontario Hydro. Presumably they are 15 customers of municipal utilities who are connected to 16 HNC distribution wires. I wanted to first of all under 17 your -- 18 MR. CURTIS: Distribution wires? Sorry. Or 19 is it transmission wires? 20 MR. SNELSON: Transmission wires. Sorry. 21 First of all you can confirm that with your proposal 22 they will not be transmission customers. 23 MR. CURTIS: Yes. 24 MR. PORAY: Yes. 25 MR. SNELSON: If you were to go to your 26 proposed long term solution, which I believe is option 2 27 of the same schedule, it's on page 9, that your option 2 28 for transmission customers is that all customers 118 1 directly connected to transmission wires would be 2 transmission customers and that is your preferred long 3 term solution. 4 MR. PORAY: Yes. 5 MR. SNELSON: And those 15 customers would be 6 transmission customers with your preferred long term 7 solution. 8 MR. PORAY: They would be. Yes. 9 MR. SNELSON: I think you started to say, and 10 you can correct me if I'm wrong, these customers will be 11 put in the position of having to establish a 12 relationship with a distribution company solely for the 13 purpose of the distribution company collecting the 14 transmission charges or paying the transmission charges 15 to Ontario Hydro Services Corporation and then charging 16 them out to these transmission connected customers, and 17 that's the only purpose in the new scheme of things that 18 these people would have to have a business relationship 19 with their local distribution company. 20 MR. CURTIS: I guess the answer to that is 21 that is at the moment, these customers do have a 22 relationship with the distribution company. I guess we 23 don't really know whether that relationship is just 24 around the notion of transferring money that they have 25 collected back to us, you know, whether they have some 26 other aspect to their relationship, I -- 27 MR. SNELSON: Currently many of them are 28 customers of the distribution company because the 119 1 distribution company has an exclusive franchise. 2 MR. CURTIS: Yes. 3 MR. SNELSON: One of the things that some of 4 these customers are taking to do is to be able to 5 provide their power directly and to not have to be fed 6 by a franchised distribution company and provide their 7 power directly in the market. 8 MR. CURTIS: Yes. 9 MR. SNELSON: And they can do that as far as 10 their energy is concerned. 11 MR. CURTIS: Under the new market rules. 12 Right. Yes. 13 MR. SNELSON: In your long term solution, they 14 would be transmission customers. 15 MR. CURTIS: Yes. 16 MR. SNELSON: But, in this interim period, 17 they have to continue some form of business relationship 18 with a municipal utility only to be able to connect 19 their transmission chart? 20 MR. CURTIS: I guess what we don't know is 21 whether there are other aspects of their current 22 relationship that are outside of the -- what you just 23 described. I mean, I think that is the only point. 24 MR. SNELSON: Okay. Did you consider changing 25 your definition to be able to include these customers as 26 transmission customers? 27 MR. CURTIS: You mean, in terms of arriving at 28 our proposal? Did we consider -- 120 1 MR. SNELSON: Did you consider that as an 2 option -- 3 MR. CURTIS: Yes. 4 MR. SNELSON: -- in for the proposal with the 5 front up? 6 MR. CURTIS: When we were trying to evaluate 7 what the proposal was, yes, we did consider that as an 8 option. 9 MR. SNELSON: Why did you reject it? 10 MR. CURTIS: I think it was the reason that we 11 talked about earlier on and that is that because of the 12 existing structure or existing setup where these are 13 currently customers of other utilities,generation if you 14 will, or other utility entities within Ontario, we felt 15 that the conversations or discussions and the reviews 16 would have to be made in order to actually make that 17 transition for these customers to actually become 18 customers of just the transmission entity. 19 MR. SNELSON: Apart from this issue of your 20 discussions with the municipal utilities -- 21 MR. CURTIS: Yes. 22 MR. SNELSON: -- and I suspect that those 23 actually are pretty much irrelevant -- but that is my 24 opinion, not yours -- is there any other technical 25 reason why it wouldn't be feasible to include them as 26 transmission customers at this stage. 27 MR. CURTIS: I don't think from out 28 perception, there is. No. 121 1 MR. SNELSON: The other question is that we 2 are talking about who are transmission customers for 3 this proceeding and you have talked about a longer term 4 aim to produce a definition of transmission customer 5 that is consistent with the new market structures and 6 new market paradigms. 7 On what schedule are you proposing to move 8 forward with that resolution of who should be 9 transmission customers? 10 Is there something which is there for -- this 11 is the two month period and then we will have a new 12 proposal for each study, January 1st, 2001 or is this 13 something that is going to take place on a longer 14 schedule. 15 MR. CURTIS: Well, I think from our 16 perspective, we would like to move it along fairly 17 quickly but I guess we are not -- our sense is that we 18 are not the ones that necessarily control this whole 19 process. 20 So, it would have to be a matter, I think, 21 resolved between ourselves, the Board, and the IMO and 22 utilities that are currently part of -- that currently 23 have these customers as their customers. 24 So, us, as an entity, would like to move it on 25 quickly but you know, we are one of the other entities 26 that are going to have to resolve this issue. 27 MR. SNELSON: I can understand that you want 28 to move it along but I don't recall you having moved it 122 1 along very much in the discussions and the consultation 2 process that the transmission customer issue seemed to 3 surface late in that process. 4 MR. CURTIS: I think that is because the 5 consultation process was dominated by other issues and I 6 think that that is what the reaction is as far as that 7 is concerned. We have had some discussions, though, on 8 this. 9 MR. SNELSON: Okay. Now, I want to move on to 10 line connection assets and who paid -- particularly for 11 customers who have paid part of that cost and Bruce has 12 asked one of my questions on this. 13 We determined, I believe, that a customer who 14 has paid for a part, but not all of this connection 15 cost, is in the pool that pays the full connection 16 charge. Is that correct? 17 MR. CURTIS: Yes. 18 MR. SNELSON: Do we know -- do you have 19 statistics on the proportion of connection costs that 20 industrial customers, on average, have paid in the past 21 because I believe that you had a policy in the past of 22 certain circumstances taking capital contributions from 23 industrial customers when they connect to the system? 24 Do you have past data on that? 25 MR. CURTIS: I don't know that we have it in 26 maybe the detail that you are requesting but we will 27 have to check that. 28 MR. SNELSON: Okay, and that is something that 123 1 we will likely ask for in interrogatory. I am giving 2 you a kind of a prior warning of that. 3 MR. CURTIS: Okay. Alright. I am wondering 4 though, if we are not confusing some issues here and it 5 is this issue of capital contribution to keep the pool 6 whole. Those sorts of contributions, we may not have 7 all of that historical data on because they were arrived 8 at in terms of negotiating with customers. 9 But, effectively what they are paying for 10 then, are the services that they are using, under 11 instances like that, through the full rate. 12 MR. SNELSON: Can you tell me whether you had 13 a comparable policy for municipal utilities in requiring 14 municipal utilities to pay a part of that connection 15 cost in similar circumstances. 16 MR. PORAY: I don't know. 17 MR. CURTIS: We don't know. We will check 18 that. 19 MR. SNELSON: Thank you. 20 MR. RODGERS: You are going to have to ask 21 that in interrogatory. You think it is in important to 22 do that do you? 23 MR. SNELSON: Yes. 24 Coming back to the subject of delivery points, 25 we have dealt with customers where there is the 26 possibility that there will be more than one customer 27 for delivery point or more than one delivery point for a 28 particular facility. 124 1 I am interesting in the definition of delivery 2 point for a customer that is fed from two separate 3 points from the transmission system. 4 So, you might have an industrial plant that 5 has more than one supply into it from the transmission 6 system. Is that plant considered to have two delivery 7 points or one delivery point? 8 MR. PORAY: Two delivery points. 9 MR. SNELSON: In determining the peak load of 10 that plant, are you proposing that the delivery point's 11 loads be summed before you determine the non-constant 12 peak load, or after you determine the non-constant peak 13 load? 14 MR. PORAY: Our assumption is that they were 15 determined separately. 16 MR. SNELSON: So they would -- you determine 17 the non-constant peak at each delivery point and then 18 the customer would essentially get two bills or they 19 would be added together on the same bill -- 20 MR. PORAY: Added together, yes. 21 MR. SNELSON: -- for the -- 22 MR. PORAY: The sum. 23 MR. SNELSON: All right. Can you tell me how 24 that is done today? Is the peak aggregated today before 25 that bill is determined? 26 MR. CURTIS: I think we will have to check 27 that. 28 MR. SNELSON: They also have some implications 125 1 for the issue that Bruce is getting towards, as to the 2 consistency between your forecast of non-constant peak 3 loads for determine the rate and the way in which the 4 rate is actually going to be bill and whether in fact, 5 they do reconcile. 6 That is what services for existing embedded 7 generators at exhibit B, tab 11, schedule 1, pages 12 to 8 17. You have a -- on page 17, there is a table which 9 shows what reports to be the average impact on the 10 customers who received backup service today. 11 MR. PORAY: On page 16? 12 MR. SNELSON: Page 17. Page 16 and 17. 16 13 and 17. 14 We will be asking interrogatory for the detail 15 behind this because we want to see that but I wanted to 16 find out today whether you have done that on a customer 17 by customer basis because averages can hide higher 18 impacts on individual customers. So, have you done that 19 analysis on a customer by customer basis? 20 MR. PORAY: This was done on an aggregate 21 basis which is taking the total of all the customers 22 backup. It wasn't done on an individual basis. 23 MR. SNELSON: So it is possible that hidden 24 within that aggregate there could be a much larger 25 impact on some of the customers that are involved there. 26 MR. PORAY: I guess that's possible. 27 MR. SNELSON: Thank you. My next reference, 28 and probably stepping backwards and forward through your 126 1 books, Exhibit D, tab 5, which comes back to another 2 subject that is of some interest in this proceeding 3 which is net versus gross load billing. 4 In this whole schedule, Schedule 1, you are 5 discussing various options when you embedded generations 6 and many of them involved gross load billing, some of or 7 all of the load for some or all of the charges. My 8 question is: How do you propose to accomplish gross 9 load billing when you require that embedded generators 10 have meters installed upon them that are read on an 11 hourly basis by the IMO? 12 MR. PORAY: That will be necessary, yes. 13 MR. SNELSON: Well, if you have that, there's 14 a local load which is being supplied to two meters, 15 being supplied with a meter from the transmission system 16 or whatever its net load is that is taken from the 17 transmission system. It is also being supplied from the 18 meter through its own local generation which is embedded 19 and is being billed on a gross load basis on the sum of 20 those two meters. 21 MR. PORAY: On the sum of those two meters. 22 MR. SNELSON: And I would ask the same 23 question about aggregation. Are those two meters added 24 together before the peak load of the facility is 25 determined or are the two meters read separately and the 26 separate peaks determined and then that becomes the 27 charge to the embedded load? 28 MR. PORAY: It's the aggregate peak. 127 1 MR. SNELSON: In this case it's the aggregate 2 peak. Okay. Is there anything in your proposal to tap 3 the gross load billing at historic load? Part of the 4 gross load billing is that the transmission system was 5 built to meet the historic load in that facility and by 6 installing embedded generation then that part of the 7 transmission system isn't being paid for by the load. 8 They could escape the charges if they went in that 9 billing. 10 This argument doesn't apply if there is an 11 increase in load at the same time or subsequent to the 12 installation of the embedded generation. I'm wondering 13 if there is any proposal to cap the gross load billing 14 at the historic load. 15 MR. PORAY: Yes, it is. It's capped at the 16 historic load. 17 MR. SNELSON: And whereabouts in the 18 submissions is it capped? 19 MR. CURTIS: I think we were discussing it 20 within the context of the existing system. This whole 21 issue around net versus gross load has been based on 22 installation of generations serving existing load. I 23 don't know that -- I guess that's been our assumption 24 and it has been understood that that's what we are 25 talking about. 26 MR. PORAY: You can't be sure that all the 27 load is existing load and there won't during the course 28 of this gross load billing regime, however long it 128 1 lasts, if it's approved that there won't be no growth, 2 there could be low growth, and so -- it seems to me 3 there should be some reference to that in here. 4 MR. SNELSON: No. We take your comment. 5 MR. ROGERS: Well, you have just been told. 6 You don't want us to amend anything now do you? 7 MR. SNELSON: What's that? 8 MR. ROGERS: We are rebuked. You have been 9 told what the position is. You don't want us to amend 10 the application, do you? 11 MR. SNELSON: I would like some clarification 12 of how it would be applied in this case. 13 MR. CURTIS: Okay. And we are agreeing that 14 what we are talking about here is capping it at a 15 historical load basis. 16 MR. SNELSON: I don't see a mechanism in here 17 to cap it up, the load, right? 18 MR. ROGERS: You want to know how it's going 19 to be done. 20 MR. SNELSON: It seems to me there is still 21 some further clarification in that regard. 22 I believe those are my questions. Thank you. 23 MR. THIESSEN: I guess that's it. Any other 24 questions? We are going to get the map. 25 MR. FAGAN: This is in relation to cost 26 determinate for network service, the coincident peak, 27 cost determinant. It's at Exhibit D, 4, tab 4. 28 Schedule 1, page 31, there's a reference to the 85 per 129 1 cent. In that area you just described the compromise 2 that you came up with, that is either coincidentally now 3 or 85 per cent of the seven to seven hours. 4 I just would like you to kind of talk a little 5 bit about how you came up with that 85 per cent 6 compromise, in particular as it compares to option 16, 7 the average demand over 50 hours per month, as a way to 8 mitigate concerns about gaining or free ridership of 9 avoidance of charges. 10 If you admit in the application it is somewhat 11 arbitrary, just give a little more background 12 information about how you came to that decision as 13 opposed to choosing option 16. 14 MR. PORAY: I think the value of 85 per cent 15 was a combination of the coincident factor and the 16 average load factor on the system side. 17 MR. CURTIS: What was the other option number? 18 I'm sorry. Sixteen? 19 MR. FAGAN: Option 16 on the prior page, page 20 7 and (inaudible) the top 50 hours of the month. 21 MR. PORAY: I think our preference for option 22 18 was that this was somewhat less complex than option 23 16 in trying to predict ahead of time what the highest 24 50 hours would be when you are trying to focus the load 25 to determine the rates. 26 MR. FAGAN: Do you feel it's really important 27 to have to fill out ahead of time that it will be this 28 seven to seven period as opposed to saying we will 130 1 charge you on a coincident peak and we will take the top 2 50 hours? We don't know exactly what the top 50 hours 3 will be. Can you talk a little bit about that? 4 It has been raised before. One of the 5 concerns would be every day at 7 p.m. or every day at 6 6:59 a.m. you are going to see some big jumps. By 7 specifying that ahead of time, you know, you might set 8 yourself up for some strange happenings at that boundary 9 point. 10 MR. PORAY: I think we thought that having the 11 peak period is a more defined period within which to 12 capture the peaks. 13 MR. GOLDSILVER: I have one quick question on 14 the treatments of new connection facilities. In your 15 application, under tab 7, you mentioned in the short 16 term, new connection facilities will be added to the 17 connection pool, whereas, in the longer term, it will be 18 an open, contestable, competitive market. 19 I am wondering if you can just clarify and 20 give some explanation as to what you consider the short 21 term to be and what you consider the long term to be in 22 terms of a time frame? 23 MR. ROGERS: Could you identify yourself 24 according the mic? 25 MR. GOLDSILVER: Erik Goldsilver. 26 MR. ROGERS: Thank you. 27 MR. GOLDSILVER: Sorry about that. 28 MR. CURTIS: At the beginning or the outset of 131 1 the market, I think there is going to be some concern 2 about whether or not there actually exists a competitive 3 market place to provide new connection facilities and 4 that -- our understanding of the way the legislation has 5 been crafted and hence the rules that are dictated to 6 the OEB is that the OEB has to regulate new connection 7 facilities because they would be considered to be 8 transmission facilities, at least up to the point where 9 they feel confident they could forbear on regulating 10 that. 11 For them to be able to forbear on regulating 12 new connection facilities means that there has be a 13 competitive market place in existence so that customers, 14 when they want to install new connection facilities, can 15 have a number of competitive options in which to realize 16 that. 17 I think that counter to that is that I think 18 it is acknowledged that under open access, customers 19 will have the ultimate choice in the ultimate phase. 20 So, I think our anticipation is that at the 21 point when open access is declared, there will be some 22 customers that feel quite confident that there is a 23 competitive market place for new connection facilities 24 and so we will be out, you know, issuing RFPs, if you 25 will, to have these new facilities built. 26 There will be other customers that won't have 27 that same level of confidence or same level of assurance 28 or even the abilities to go out and do that and so they 132 1 will want to have the existing pool structure available 2 in order to make these investments. 3 So, what we are actually presenting here is 4 that the short time potentially could be quite short 5 depending on what happens at the point of open access 6 and how many customers that are seeking new connection 7 facilities feel that there is a competitive marketplace 8 in existence for them to get that. 9 We are in, I guess, the same sort of dilemma 10 with many of these other issues in that we are not the 11 ones that are going to determine what happens in terms 12 of these facilities becoming competitive or staying 13 within the regulated pool. What we are stating is what 14 we are feeling is going to happen here, going into the 15 future. 16 So, I think what we are -- at the point of 17 open access, I think probably both options will exist 18 for customers. 19 MR. GOLDSILVER: So, it will be a customer 20 choice. 21 MR. CURTIS: That is what we see as the 22 overriding driver is the customers, under open access, 23 will have the choice in terms of you know, how they 24 would go about doing this. 25 MR. GOLDSILVER: Thank you. 26 MR. SHALBY: My name is Emir Shalby, 27 representing the IMO. I have two areas of questions. 28 One has to do with the export and wheel-through charges 133 1 and one has to do with the definition of transmission 2 customers. 3 Let's start with tab 6, the export and 4 wheel-through proposal. Tab 6, page 11. 5 Tab 6, page 11 talks about the conclusions 6 amongst the options. You laid out six options for 7 charging for a wheel-through and export and chose an 8 option of charging $1 per megawatt hour. 9 Later, in page 11, starting at line 12. The 10 sentence, it starts with: 11 "It is possible to reduce the 12 transmission charge by linking the 13 revenues from the export trees to another 14 account having to do with transition 15 rights, auctions and revenues and 16 surpluses from that auction." (As read) 17 Two things that I would like clarification on 18 here. Is it your proposal that you do that or is it 19 your proposal not to do that? It is possible to do 20 this? I thought the options were discussed before -- 21 are you recommending to do or not? 22 MR. CURTIS: I guess, just to clarify that, 23 the two accounts would not be linked. What we are 24 suggesting is that the amount that would in the 25 transmission rights account would be communicated back 26 to us and for a specific generators, we would reduce and 27 on a going forward basis, the wheeling-through charges 28 to accommodate that amount. 134 1 But that amount would still remain with -- as 2 far as the transmission rights -- would still remain 3 with the IMO and the IMO would deal with it 4 appropriately according to how the market rules are 5 defining that. 6 MR. SHALBY: So it isn't really money 7 transferred? 8 MR. CURTIS: There is no money transferred. 9 MR. SHALBY: You will keep an eye on another 10 account and if somebody paid in that account, you will 11 give them some forgiveness in your own account. 12 MR. CURTIS: Yes. 13 MR. SHALBY: Is that the idea? 14 MR. CURTIS: Yes. That's it. 15 MR. SHALBY: The logic behind that will 16 perhaps be explained at another time but it is clear 17 that you are not linking the money in the two accounts. 18 MR. CURTIS: No. The money isn't flying back 19 and forth between the two accounts. 20 MR. SHALBY: I may not be happy with the logic 21 but I am happy that the one account is left alone. 22 --- Laughter 23 MR. SHALBY: If I move on to the other 24 question that has to do with the definition of 25 transmission customers who are transmission customers 26 other than NBCs and directly connected customers -- is 27 the heading of that tab. 28 And if we go again to the end of page 13, 135 1 perhaps more generally, not related to anything to 2 anything other than the conclusions in general, the 3 question is, have you assessed the implications of this 4 definition of transmission customer which is essentially 5 the status quo of customers that exist today in the 6 Ontario Hydro billing and settlement system. 7 Have you assessed the implications of that 8 moving forward into the new market and settlement and 9 need a regime that will present (off mic...) 10 The question is, does this fit in the new 11 regime being constructed right now? 12 MR. PORAY: I think that our assessment is 13 that it does fit. 14 MR. SHALBY: With ease or with conflictions? 15 --- Laughter 16 MR. PORAY: Probably with ease in terms of 17 dealing through our transition period. 18 MR. SHALBY: In the settlement logistics and 19 metering and so on, in your judgement, are compatible in 20 with the infrastructure being built and the market 21 rules?` 22 MR. PORAY: I think so. 23 MR. SHALBY: Perhaps we will get a better 24 meshing of the meter reports and the readings that are 25 needed to settle the transmission accounts compared to 26 the seven points in reading that the marketplace is 27 going to be putting in place for the settlement of the 28 market administered by the IMO. 136 1 If we can get that message to assure us that 2 in fact, there are no additional meters required for 3 example or nothing more substantial that what he have 4 now. The settlement routine is compatible with the 5 chapter in the market rules -- 6 MR. CURTIS: Yes. I -- 7 MR. SHALBY: Any deviation of that would be 8 helpful to us. 9 MR. CURTIS: Right. I guess maybe, the issue 10 for us is whether there is stability around the 11 transmission of customer from the IMO perspective in 12 terms of the -- you know, how the market is going to 13 operate. 14 I think what we are proposing, going with the 15 existing the definition of the transmission customers 16 definition is that there is some stability in terms of 17 how the customers are defined. 18 I think one of our problems was that when we 19 looked at how the market rules were being put forward, 20 customers were going to have the option to define 21 themselves as a transmission customer one month and 22 maybe two months later defining themselves as not a 23 transmission customer as far as the IMO settlement was 24 required. 25 It is just that second half of what you were 26 talking about. I think we can provide you with who the 27 customers are -- the transmission customers are -- and 28 whether or not there are metering points that exist for 137 1 those. 2 MR. SHALBY: This chapter concludes by the 3 result to hold consultations with NBCs, IMO and others. 4 MR. CURTIS: Yes. 5 MR. SHALBY: So, invitation is open to get on 6 with those consultations at least with the IMO. 7 MR. CURTIS: Okay. 8 MR. SHALBY: -- to get the metering and 9 settlement routing and are they in shape or identify the 10 gaps between what you are proposing here and what will 11 be in place. 12 MR. CURTIS: Sure. 13 MR. SHALBY: Projects like that can take time 14 to fix up. Thank you. 15 MR. RATTRAY: Just so we don't leave this, I 16 assume then you will be giving us -- I hate to invite an 17 interrogatory, but you will be giving us a short terse 18 interrogatory requesting what it is you want? 19 MR. SCHUCH: We are inviting an interrogatory. 20 MR. RATTRAY: Pardon? 21 MR. SCHUCH: We are giving an interrogatory on 22 that -- 23 MR. RATTRAY: Good. 24 MR. SCHUCH: If it keeps the -- 25 MR. RATTRAY: Well, I just don't want to 26 leave -- I don't want to lose the undertakings out there 27 so it would be best if you gave us an interrogatory and 28 then -- 138 1 MR. SCHUCH: I will do that. 2 MR. RATTRAY: Thank you. 3 MR. SCHUCH: Thank you. 4 MR. ADAMS: I have a very brief question and I 5 think it is on more or less the same point -- reference 6 from Exhibit D, tab 6, schedule 1, page 11, where you 7 make reference to the export revenues. 8 You have referred there specifically to the 9 surpluses from auction rights. Does that apply for the 10 settlement surplus as well? You are making a 11 distinction between the auction rights and settlement 12 surplus or just all in the same account? 13 MR. PORAY: No, we are making the distinction 14 to deal just with the interconnections with the auctions 15 of the transmission rights. 16 MR. ADAMS: Okay. So what happens with the 17 settlement surplus then? 18 MR. PORAY: That is part of the energy 19 component that we are not touching, we are not dealing 20 with here. 21 MR. ADAMS: Okay, okay. 22 MR. ROGERS: Are there any other questions 23 before we adjourn? 24 MR. SMALL: James Small, representing Tormont 25 Energy. 26 I am just looking for some clarification on 27 some items and hopefully get some direction in the 28 document where I can maybe find the answers. 139 1 Tab 5, schedule 1, page 7, under "Threshold 2 Embedded Generation" has the definition as: 3 "What is the basis of defining threshold 4 embedded generation as less than one 5 megawatt." 6 Was the IMO standard the only one that was 7 considered or were there others? 8 MR. PORAY: I think that the other -- the 9 other aspect was the materiality of the revenues 10 recovered from small generators. 11 MR. SMALL: The material revenue matter then, 12 it too would be treated differently under this exemption 13 or qualify for the exemption, the size issue or an 14 impact on revenue issue? 15 MR. CURTIS: Well, it was a size issue and in 16 respect of the revenues that would be collected versus 17 the costs that would be involved in terms of setting up 18 the metering and the settlement-type processes that 19 would be involved under our proposal. It is a trade 20 off. You reach -- there has to be some critical size 21 that you have to reach before it makes overall economic 22 sense to bill it on a different basis. 23 MR. SMALL: One megawatt, was that size for 24 you? 25 MR. CURTIS: Yes. 26 MR. SMALL: Page 11, you mentioned in one of 27 your options, discussions -- case by case discounting -- 28 has this been abandoned and part of the recommendation, 140 1 and if so, what was the thinking of -- page 11. 2 MR. CURTIS: This sort of consideration went 3 on through the summer in terms of our discussions with 4 various stakeholders and was considered within the 5 advisory team. I think the overall feeling was that it 6 should not be pursued or it should be abandoned because 7 it represents then differential treatment across 8 customers and a potential for cost shifting. 9 MR. SMALL: So the secondary issue didn't 10 really explore (off microphone) this advisory (off 11 microphone) options for -- 12 MR. CURTIS: Yes. 13 MR. SMALL: I noticed in tab 5, schedule 1, 14 page 14, the table you referred to, OPGI small 15 generator, it seems that OPGI is recognizable as being 16 the big guy but the small generators seem to be 17 everything from one megawatt to anything that is not 18 OPGI. Is that -- 19 MR. CURTIS: Yes, that is correct. 20 MR. SMALL: -- basically it? 21 MR. CURTIS: Yes. 22 MR. SMALL: Were you relying on anything other 23 than (Ager Menanka) report for -- how generators were 24 going to be affected by -- 25 MR. CURTIS: In terms of, for example, the 26 result on this table? 27 MR. SMALL: In terms of this. 28 MR. CURTIS: Yes. There was input throughout 141 1 the stakeholder consultation process from 2 representatives of generators, apart from OPT, so that 3 also entered into this. 4 MR. SMALL: One other matter that came up was 5 in terms of the gross load billing would be levied 6 against LDCs which as OHNC you are going to be treating 7 OHBC, the distribution company, the same way it will be 8 treating -- 9 MR. PORAY: That is the intent here. 10 MR. SMALL: Thank you. 11 MR. LIDDON: Ken Liddon from Suncor. 12 I just wanted to follow up on an answer that 13 you gave to Ken Snelson and it was with regard to a cap 14 on gross load billing at the existing load. 15 If I have a 15 megawatt plant and I double the 16 capacity to 100 or double my plant capacity and I become 17 100 megawatt load, and at the same time, I put in a 18 progeneration project, 100 megawatt progeneration 19 project, have I now got a 50 megawatt net load billing 20 portion and a 50 megawatt gross load billing? 21 In other words, you said you would cap it at 22 my historical load. 23 MR. CURTIS: Yes. Yes, your historical load 24 is 50 megawatts and now you are going to 100 megawatts 25 and in the same instance, you are installing a 100 26 megawatt generator. 27 MR. LIDDON: Right. 28 MR. CURTIS: Okay. The original 50 megawatt 142 1 load that you had, we would talk about it as the 2 historical load, would be billed under the proposal that 3 we put forward which is the connection is billed on a 4 gross load basis and the network is billed on a net load 5 basis with a 50 per cent access but it is for that 50 6 megawatts. 7 And then the incremental 50 megawatt load that 8 you are talking about, first of all, I guess implicit in 9 that is the need to negotiate a new connection deal 10 because presumably you would want to be able to supply 11 that full 100 megawatts if your generator went down. So 12 that there would be some provisions in terms of 13 negotiating a new connection agreement around that 14 additional megawatt. But if you set that aside, that 15 would be built on a net load basis. 16 MR. LIDDON: If I am a new competitor coming 17 into the market and I (microphone off) or something like 18 that (microphone off) 19 MR. CURTIS: Yes, but again, just to clarify 20 again, you would presumably be entering into some 21 negotiation with us as far as your connection agreement 22 is concerned so that -- 23 MR. LIDDON: -- connection but the network -- 24 MR. CURTIS: Yes. 25 MR. LIDDON: -- would be on a net load basis? 26 MR. CURTIS: Yes. 27 MR. LIDDON: And the fair and equity, how does 28 that relate to the (microphone off) 143 1 MR. CURTIS: Well, you are talking about a new 2 load that is coming into place and it is being serviced 3 by the new generator that you are putting in place and 4 so there hasn't been infrastructure within the 5 transmission system that has been installed to service 6 that. 7 So it -- on that basis, whereas in the former 8 example, the infrastructure has been installed to 9 service that load. 10 MR. ROGERS: Are there any further questions? 11 If not, I would like to suggest that we 12 consider adjourning today. 13 MS LITT: I remind everybody that if there 14 were matters that weren't addressed or weren't explored 15 in its entirety, that they may be taken up through the 16 written interrogatories process and that the transcripts 17 from today's proceedings should probably be posted on 18 the Board's web site by noon on Monday. 19 Thank you everyone for your participation. 20 --- Upon adjourning at 1521