THE ONTARIO ENERGY BOARD Ontario Hydro Services Company Inc. (SERVCO) Interim Transmission and Interim Distribution Applications Hearing held at 2300 Yonge Street, 25th Floor, Hearing Room No. 2, Toronto, Ontario on Monday, January 11, 1999 commencing at 9:05 a.m. --------------------- TECHNICAL CONFERENCE "Transmission Assets and Capital Plans" VOLUME 3 --------------------- F A C I L I T A T O R : DAVID HARDY Board Technical Staff 238 A P P E A R A N C E S DAVID HARDY ) Board Technical Staff KIRSTEN WALLI ) NEIL McKAY ) in conjunction with: MICHAEL HARRIS ) Reed Consulting SUSAN SIMMONS ) ANN BULKLEY ) BOB CHOW ) Ontario Hydro SUSAN FRANK ) Services Company Inc. DAVID BARRIE ) [SERVCO] MYLES D'ARCEY ) TIM DAVIES ) 239 ---Upon commencing at 9:05 a.m. MR. HARDY: Good morning. I think we are ready to begin. Welcome to the continuation of the Ontario Hydro Services Company rate order application and the first of the detailed Technical Conferences. I am Dave Hardy and I've been asked to facilitate these conferences. My area of concern is to make sure we keep the agenda on track and make sure that I have an eye to process and fairness. I'm just wondering, is there anybody who is new today, who hasn't attended any of the other Technical Conferences or the education session? Okay. So I don't see anybody so I'm going to shorten my remarks then. I'm just wonder if I could go up to the first overhead just to remind everybody where we were. We had the corporate overview last week on Thursday and Friday. As you can see at the bottom of the overhead there on -- we are moving into the first of the detailed Technical Conferences on transmission assets and capital plans. Can I have the next overhead, please. Tomorrow, we'll be moving into issues relevant to OM&A and then on the 18th, issues related to transmission PBR; the 19th, transmission cost allocation and rates. The last overhead. And then on January 20th, we'll have issues relevant to distribution assets and capital plans and the 21st, distribution, OM&A and revenue requirements. So that's how the rest of the detailed technical sessions are going to be sorting out. Overview 240 (Facilitator) At that, I want to have our first panel then introduce themselves and begin with your presentation. Who's going to be leading? Would you like to have your panel introduce itself, please. MR. BARRIE: Bob, would you like to start? MR. CHOW: Good morning, I'm Bob Chow. I'm a Director of system development with transmission network asset management. MS. FRANK: And I'm Susan Frank and I'm the Finance Director of buyers, integration and regulation. MR. BARRIE: I'm Dave Barrie. I'm the General Manager of transmission network asset management. MR. D'ARCEY: Myles D'Arcey, I'm the General Manager of engineering services. MR. DAVIES: Tim Davies, I'm the director of asset sustainment in TNAM. MR. HARDY: Okay. We will have your presentation and then we'll have questions from Board Staff. I know there one or two people with time constraints so we'll have -- try to make sure we entertain those questions this morning as well. So why don't you go ahead with your presentation, please. MR. BARRIE: Good morning. PRESENTATION BY MR. BARRIE: As Dave mentioned, this panel is to discuss the specific issues relating to the OHSC transmission rate order application. The panel has already been introduced Presentation 241 (D. Barrie - SERVCO) so I won't go over that again. Today we want to deal with issues surrounding the transmission assets and the capital plans and tomorrow we'll deal with the OM&A and the revenue requirements. I propose a short presentation, about a dozen overheads or so. The intent is not to reiterate what has already been submitted in the written material, it's more to provide some context and some additional material that I thought might be useful based on the questions that were posed to Panel 1 to the extent that I've been able to try to get that information together over the weekend, that is. There are six parts to the presentation. I'll start by providing an overview of what the transmission system is, what our assets consist of. I'll go on from there to cover the transmission business strategies, tying them to the changes in the electricity industry, and the broad strategies that were described by Rod and Ron last week. I move from this to discuss the transmission business planning process and the specific aspect as they relate to the capital plans. A brief overview then of the '99 2000 transmission capital program. I'll simply be trying to identify the trends and the rationale for those trends rather than individual programs which are already listed. I'll then touch on some benchmarking to indicate to you how the transmission business in Ontario compares Presentation 242 (D. Barrie - SERVCO) with other transmission businesses around the world. Finally, in response to more questions posed last week, I will show how the transmission business is organized and the numbers of staff involved. So that will be the majority of all the presentation. To finish off with, Myles D'Arcey will then discuss how the work execution is organized and the staffing involved in that. So that's an overview of what I'm going to talk about. So if I could have the first overhead, please. First, what physically comprises the transmission system? Well, first of all, given the poor visibility for overheads on Thursday and Friday, we have arranged for copies of all the overheads to be available. They are over here, are they, Bill? So there's copies of the overheads over here if anybody needs them. So in section 4 of the application, it lists the assets and, in fact, this diagram is on page 21. Just to clarify, when I showed this diagram to one of my non-engineering colleagues he wondered what the strange birds were flying around diagram. These are the standard indications of transformers which indicate changes in different voltage levels but I'm sure everyone here knew that. A couple of points of clarification. As the enterprise manager of the transmission company, which was Presentation 243 (D. Barrie - SERVCO) the phrase the group were using there last week, I regard the following as direct users of the transmission system. First of all, all generators, and I show the Ontario Hydro generation on the left-hand side of the diagram and non-utility generation on the top, and any other generators that will be connected in the future. We also have some 105 large directly connected customers. We have 74 municipalities connected to the transmission system. In addition, we have the Ontario Hydro distribution system. As well as that, we interconnected with three states and two provinces. So those are what I regard as my direct users. We also, on this diagram, I put across the notion that the transmission system can be classified as either network or connection, and later panels will discuss this in detail, but that's the two shadings of the transmission network shown there. In terms of the boundaries, there was some interest expressed in that last week. The details of the boundaries between the distribution and the transmission system and the generation and the transmission system are provided in supplemental filing "I". And if you have any questions on that, I'll be happy to try and answer them. I will simply say at this juncture that the boundary definition used in those - there are two documents there - were consistent with the transmission system's function as a bulk carrier of generation to bulk delivery points. Essentially, we use 50 kV as the Presentation 244 (D. Barrie - SERVCO) dividing line between distribution and transmission and that is applied practically to the extent we can. Can I have the next slide, please. This pie chart simply reflects the breakdown of the assets in terms of their net book value. All of this is shown in detail in chapter 7 of the application. Just very briefly, the high voltage lines which are shown there comprising 500, 230, and 115 kV, represent some two-and-a-half-billion worth of assets. And we've shown the stations individually, but essentially if you add up all the stations, they all add up to a similar amount to all of the lines. But as I said, indeed the break down is in the application, so I don't propose to say much more about that. I do want to draw one thing to your attention. We have a sector there called 'other' which is described in the application, but I wanted to bring up one in particular. When Ontario Hydro acquires land for a transmission addition, particularly on strategic rights-of-way, we sometimes acquire sufficient land to accommodate long-term growth but initially may only use part of the land. When this occurs, the land not used initially is classified as land held for future use and is held in a separate account. There is some $70-million worth of such land in the transmission assets and is shown as part of Other. If I could now move on to what I've called here specific transmission strategies. This also tends to get Presentation 245 (D. Barrie - SERVCO) into the kind of drivers we have that are the essential underpinnings of the programs that I'm about to describe. Rod and Ron did describe some broad strategies for Ontario Hydro Services Company, and these strategies I'm going to speak about are specific to the transmission system. Now, the first one is, we must meet system security and reliability obligations. First of all, it's good business to do that and the government, in fact, mandated that in the move to open access, transmission reliability was not to suffer. There was to be no degradation in system reliability. So that is clearly one of our essential requirements. We are connected into the North American grid and therefore a part of NPCC, Northeast Power Coordinating Committee -- Council, rather. And, as such, we have certain specific requirements that we must adhere to as part of being a member of NPCC. However, we do satisfy those requirements at this moment in time and we do not expect there to be any changes that would require any major increase in our capital program to continue to satisfy NPCC requirements. In the filing, we do indicate the age of our assets. One of our concerns is that we do have a lot of old equipment, both lines and stations. In 1997, we did initiate an asset condition assessment study partly because of the age of equipment and partly because this was a review to be done by all business units within Presentation 246 (D. Barrie - SERVCO) Ontario Hydro. As a result of that condition assessment, it revealed in many classes of equipment some real concerns about the condition of equipment. So many of our programs are focused on maintaining reliability in the face of those concerns with the asset condition and the aging equipment. To do all of this, as Ron mentioned last week, we have implemented an asset management model and we are focusing on asset condition. If one looks at the performance of the transmission system over the last few years, it is not evident that there is any degradation at this point in time, but I do want to emphasize that in our opinion, asset condition is a precursor of performance; that is, performance tends to lag a deterioration in actual equipment. So we haven't seen it yet in terms of reliability, but if we don't do anything, we believe it will deteriorate. The second one I'd like to speak about is enabling competition. As a transmission provider, the ideal situation for me is that the transmission system is transparent to the market; that is, to the maximum extent possible, we would like the market to function with there being as little as possible impediments to the market caused by transmission constraints. The one item of particular note in our capital plans surrounds the interconnection. We do have plans to Presentation 247 (D. Barrie - SERVCO) increase interconnection capability with neighbouring states and provinces by some 2,000 megawatts. This is consistent with the market design committee's recommendation on market power mitigation measures which was endorsed by the Ontario cabinet. So we have taken that to be one of the things that we have to achieve in the next three to four years to improve interconnection capability by some 2,000 megawatts. The third bullet there refers to business efficiency. As we move into a more competitive environment, there is pressure on all of us to become more efficient in the way we carry out our business and that will be identified in a number of areas; first of all, how I as an asset manager define the work to be done. We believe we will do that better in the future as we implement things like reliability-centred maintenance. Then there is the unit cost of actually doing the work and Myles will speak to that, but again, the pressure is on to reduce unit costs and overall to create a more efficient business enterprise. The new relationship with customers bullet there refers to the fact that in the old Hydro, Hydro has - well, has right now until the 1st of April - a relationship with customers based on a bundled transmission distribution supply and the energy surrounding it. In the future, the transmission business will have to establish a relationship with customers based on providing a transmission service. This will be a new Presentation 248 (D. Barrie - SERVCO) venture for both us and the customers. The last point I just wanted to note is environmental stewardship. We have in the past had a strong program of environmental stewardship and we will be continuing this in the future and it is embedded in many of our programs. Okay, if I could move on. Many of the things I've just spoken about are, in fact, the drivers for our programs. Just very briefly, we must meet the requirements established by the regulator and by other legal requirements upon to us meet environmental issues and safety concerns. We must meet system performance requirements in terms of what I mentioned, NPCC and our customer requirements. We have programs associated with improving shareholder value; that is, to optimize the business. So we have -- you will see there are programs in there intended to make us a more efficient business and thereby enhance the value of the transmission business. And finally, another driver we have relates to responding to the strategy put forward by the Ontario Hydro services company. An example of that might be where we have an environmental program that goes beyond the minimum required by the legal requirement. We may choose to do more if that is the strategy developed by the Ontario Hydro services company. So those are the kinds of drivers we have. Of course we have constraints upon our program, Presentation 249 (D. Barrie - SERVCO) the first one of course being money - what can you afford to do? Another constraint we have in actually executing the program that may not be obvious to everyone is that many transmission additions or a lot of the programs do require equipment outages on the existing facilities in order to do the work, so that is frequently a constraint as to when we do the work. And another constraint we have that is probably unique to the transmission business rather than, say, the distribution business is that many of the plans we have involve unique huge equipment which may have very few equipment suppliers. If you read about the phase shift as we speak about from Michigan for instance, there are only actually three or four suppliers of such facilities in the world today, so there is some limitations there as well. So those are the constraints. Having said all that, our process then typically involves obtaining data information both in terms of system growth, asset condition, et cetera, et cetera. We analyze that. We establish need. We develop alternatives. We seek solutions. We integrate across all of the programs and we develop a set of programs. All of these, of course, have been filed in some detail both in the original application and in the subsequent filings, so I don't intend to get into them in any further detail. The next slide. There was some questions raised last week about the way we classified the programs, so I thought I'd just clarify what we mean by the four Presentation 250 (D. Barrie - SERVCO) categories that you will see repeating themselves both in the capital program and in the OM&A program. These are the four categories we typically use: First of all, development. Development covers reinforcing internal network and interconnections to meet both network needs and new connection needs, so it tends to be an addition to capability. In addition to that, it can also cover additional facilities that might be put in, not because there's any growth but because there's some inadequacy in the original system design, but it tends to be adding something. That is the essence of development. Sustainment on the other hand involves assessing the capability of existing facilities and doing remedial work to bring the facility back to its original intent. We did file in some of the appendices some fairly detailed strategies on our whole asset sustainment work, so I won't go into any other further detail on that. The third category is operations. Now, last week it was noted that when Ontario Hydro successor companies are formed, the IMO is the system operator. So I'd just like to clarify exactly what that is. The IMO is not the system operator in fact. The IMO is charged with directing system operations. I make that distinction because the IMO does not have any physical capability to operate any equipment at all and indeed, that is generally true of all ISOs across the world. The owner of the transmission facilities has the physical capability to operate its own equipment. So we do have around this Presentation 251 (D. Barrie - SERVCO) province some 17 locations that actually have physical hands-on control of the facilities and we have some four supervisory centres that oversee the work of those 17 centres. So we have two tiers of operation within the transmission company. The capital that you will see in the operations program is really to amalgamate the four supervisory centres into a single transmission operation management centre and to amalgamate the 17 operating centres into ten. So those are the numbers that are in there and that is driven strictly by efficiency. We are able to do that now with the technology now available for supervisory control. I'll be happy to try and answer any other questions on operations in a question and answer session. The fourth element is transmission support and this covers a whole host of support activities not directly in TNAM but which I rely upon to carry out my business, things like high level strategy, HR, finance, regulatory affairs, legal, that kind of thing. These are provided at the OHSC level and assigned -- and the costs assigned to me. The allocation of those costs was discussed in Panel 1. Okay. So having said all that at last I now get to the capital program itself. An overview of the capital program was provided in the original application. There was further information then provided in the supplemental filing of December the 23rd. And that was further supplemented by Presentation 252 (D. Barrie - SERVCO) program details in the January 4th filing, Filing "I". I would like to speak to the trends and that's all I'd like to do at the moment. First of all, the sustainment trend. You see a fairly substantial ratcheting-up of the sustaining capital. And this is specifically to address the points I've already covered in the Asset Condition Assessment and the aging equipment. So the intent of that sustaining capital is to prevent deterioration of system performance. The development capital as you see increases from '98 to '99 and stays at about that level in 2000. '99 is largely in response to the ice storm so there are specific capital programs in there which respond to the damage done by the ice storm. And 2000 is largely driven by the interconnection capital. Moving on to Operations, you see a fairly significant step up between '98 and '99 and that is to do with the amalgamation of the operating centres that I've already mentioned. Transmission support ramps up from '98 to '99 and then goes back down in 2000 and that is all to do with the start-up costs of the new company and the de-merger activities going on now. So those are the principal trends in the four elements and that's all I have to say on that. Okay, if I could move on, one of the things I think I would like to try and do is indicate where we, the transmission company in Ontario, stand compared to an Presentation 253 (D. Barrie - SERVCO) international comparison. We do participate in a benchmarking activity called the International Comparison of Transmission Performance, ICTP. That's about twenty transmission utilities from around the world. The work done there compares critical indices on the performance of all the transmission companies. The latest figures we have are for 1996. The first one I'd like to show is Costs. I think this is a good index for a transportation company. How much does it cost you, total cost that is, both O&M and capital, to move a quantity of over a certain distance? So this is O&M and CAPEX per megawatt hour kilometre. I cannot tell you who all the other companies are because that is a confidential agreement that we do sign when we participate in this, but I do indicate there where we stand. So we are a low-cost transmission provider based on this index. The other side of the coin is the quality of that supply. The measure here is the amount of undelivered energy caused by transmission interruptions and we don't fare so well on this one. It is actually the fifth one from the right where the pencil indicates there. So we are just in the third quartile, almost bottom quartile in terms of performance. Now, one has to put forward a caveat on this particular one because it varies tremendously based on the type of transmission company you are. A lot of our Presentation 254 (D. Barrie - SERVCO) undelivered energy is caused by single circuit supplied particularly in Northern Ontario where a huge distance is involved and we have a very skinny system. If you were to remove those we would be about average. So just to reiterate, our programs are aimed at maintaining our current performance to prevent further deterioration. I wanted to touch on Performance Measures briefly. They are described in section 5.3.12 in the application. I want to highlight them because - and I think Ron alluded to this on Thursday - they are a means of driving change. We as a company realize that we have to change. We have to get more efficient, for instance, and it is these measures which we believe will be one method which will underline these changes. They're part of the evolution and development of PVR - and I know we have a panel specifically on that later - but they are important to us and they are, in fact, the measures we use to manage within the transmission network asset management business. And to achieve a lot of this, TNAM uses service level agreements with our service provider to establish response times, reporting mechanisms and to execute the work. And Myles will speak about that when I'm finished. Okay. Last week there was a lot of discussion about the organizational changes and I'm hoping to try to Presentation 255 (D. Barrie - SERVCO) clarify. I show here the Wires Operations. Ron Stewart described there is a clear separation between decision- making and work execution. So I show these six entities here, the two on the left being the decision-makers, the four on the right being the way we organize to execute the work. I would like to describe in detail what is in the TNAM box, which is what I'm responsible for. Next week you have Vetnam Suri(phoen) up here on Distribution so I'm sure Vetnam will be delighted to tell you about DNAM. And following my presentation Myles D'Arcey is going to describe the organization of the four on the right, the work execution. So this is how I have my business organized; I have four divisions. We've already spoken quite a lot about three of them, in fact, and, in fact, two are represented here. So I have a group look at specifically System Development programs; another group look at Asset Sustainment and the two directors are here. I have a division of Transmission Operations. The director of Transmission Operations is not here. I'm going to answer any questions you have on Transmission Operations. I had to leave someone back to look after the shop while I was here. We have a division on Policy and Standards which looks at things like -- I mentioned the development of reliability-centred maintenance, the development of a grid code, development of standards. That kind of thing is all Presentation 256 (D. Barrie - SERVCO) handled in the Policy and Standards Division. We have a total of about 210 staff in TNAM. Because this is a decision-making group we don't have many tradesmen. In fact, the only tradespeople we have really are in the operating group. We have about 40 of those, about 20 managers, and about 140 engineers. So that's the 210. So with that, I'd like to hand over to Myles and ask him to continue. Thank you. MR. D'ARCEY: Thank you, Dave. PRESENTATION BY MR. D'ARCEY: I just want to give you a brief overview of how we're organized to execute work. I guess the primary focus of what we're looking at is within the services side of the business, the delivery portion of it that work is work is work. We focus on maximizing the resources which we have, maximize IT, maximize the fleet which we have available to us to ensure that we make the best use of those things in delivery of the services to our various customer or clients, TNAM being one of them, DNAM being another and a small portion of the work which is also external. Within the service delivery side of it, we have the Maintenance, Construction and Operations which consists largely of the field presence. They habitate some 170 locations across the province and service the transmission needs across some 600,000 square kilometres Presentation 257 (M. D'Arcey - SERVCO) of Ontario. They are divided into four territory groups which are the administration hubs for those territories and they have some 2,300 staff that are associated in the delivery of those services. There are also 15 zones which are associated with the lines function of it, the line maintainers, which also provide services on the transmission lines. We have the Engineering Services group which is primarily accountable for two functions, one is the design component with regards to a design/build function providing a design on transmission lines as well as transmission stations and they also have a function with regards to work packaging, preparing the work packages for the field for the delivery of the work with the various services that we provide, the products and services. On the commercial operations side of it, that houses our Forestry group which is divided into four divisions or four zones within the province, again administration hubs. They also contain the telecom component of the business and our central maintenance shop which is located in Pickering which does overhauls on the transformer breakers and regasketing and that type of work. We also have a Logistics group. Within the Logistics group they have accountability for the real estate component of the organization. They also have the supply chain or material component, procurement and Presentation 258 (M. D'Arcey - SERVCO) delivery and the fleet, and the fleet component. They manage the fleet, some over-5,000 units both trailers, equipment and vehicles. Just to give you a rough overview of the makeup of the organization as far as the type of trades which we have in the field, there are some 1100 line maintainers in the province, there are some 410 foresters, 230 electricians, mechanical maintainers, we have 190. P and C technical, which is a field presence for the Protection and Control group is about 190. We have about another hundrerd -- 610 Trades group which consists of anything from janitorial, building support, technicians, customer service group. We have some 95 meter readers, Customer Service group of 250, Field and Supervision, which is also clerical support, is about 350. We have the OHSC services function which is the portion of the services side delivery component for support which is about some 300, and then we have some 300 engineering people which also includes drafting, engineering, mechanical and electrical components and some 250 operators in the province. So in total, in the services components, in around some 4200 staff associated with the delivery of services within the province. And in addition to that, we also have some 670 staff which are temporary staff or from our hiring hall components both EPSCA and PWU. As Dave mentioned, we've established within the organization sort of an arm's-length relationship between Presentation 259 (M. D'Arcey - SERVCO) the decision-maker, being the TNAM component and the service delivery component, and we've developed the commercial-based service level agreements which form the basis for how the services which we provide are delivered. These are in about 160 service level agreements for both the transmission and the distribution side of the business. They specify delivery performance targets for within -- for each particular product and service as well as unit prices in some -- when available. As this shows, the main primary focus with the asset management group is the decision-making group to remove that from a resource based organization which we were previously, and more of a focus on central decision- making and the network services component which would focus on the delivery of those services. The services then, the performance indicators is then collected from the field and the information then is provided back through to the service provider to condtinue the process then of ongoing analysis then on the assets. And again, the creation of programs which again then are developed into revised service level agreements and performance in the future. Thanks. MR. HARDY: Thank you, panel, for the opening presentation. What I'm proposing is that we begin with the questioning as to have Board Staff and Consultants to begin at an appropriate time or the break, whichever comes [Questioning] 260 Consultants/Board Staff first, then I'll open up questions to participants as well. So Board Staff and Consultants, are you ready with your questions then? Would you like to reintroduce yourself for participants as well. MS. WALLI: Kirsten Walli, Board Technical Staff. MR. McKAY: Neil McKay with Board Staff. MS. SIMMONS: Susan Simmons with Reed Consulting Group, Consultant to the Board. MS. BULKLEY: Ann Bulkley with Reed Consulting Group. MR. HARRIS: Mike Harris, Reed Consulting Group. MS. SIMMONS (Reed): Susan Simmons, I'll begin. Q. I just want to confirm, on this, one of the overheads here, second to last page, Labour 1999. This is for total transmission and distribution; is that correct? MR. D'ARCEY: A. That's correct. Q. Are there certain categories of staff that only serve the transmission function or all of these staff could technically be either in transmission distribution. I'm specifically interested in, you know, where there's -- where people work on both systems or where they are just specifically assigned to one element? A. There are a lot of synergies between many of the trade groups that we have there. If you were to -- want to pick out one group, I guess the operating group would be directly related to the transmission facility. Q. And the customer service and meter readers, [Questioning] 261 Consultants/Board Staff are they primarily with distribution or what sort of customer service do you provide on transmission? A. The customer service is divided into two portions, one is in the delivery of the services for the distribution side of it, and there is some customer service support for the transmission side with regard to new connections and management of the MBU contract. Q. Okay. Thank you, very much. I think that's all I have with respect to follow up on that. I'm going to ask some questions that we touched upon in the first panel just to hear from your side with respect to the asset management model. We heard from Panel 1 as to why this model's being developed, but I also want to understand your experience in deciding to implement this. And I want to get a handle on how the process occurred internally to make this decision to move to an asset management model and whether you were consulted or you participated in the decision to move to this and I guess that's my first question. It's to anyone on the panel. MR. BARRIE: A. I guess it's to me. The asset management model, I guess, was initiated a couple of years ago, there was some discussions going on with other utilities who had adopted this model. At that point in time several senior managers in the transmission and distribution business did discuss the pros and cons of the model and the decision to go that way occurred, I'm not sure when, exactly, but I think it was sometime in '97. [Questioning] 262 Consultants/Board Staff Q. And can I just follow up on a statement that you made. You said there was a discussion of the pros and cons. What are the disadvantages from your perspective on implementing this sort of management structure? A. There is a disadvantage that has to be managed and that is a single company, as Ontario Hydro was, have people in the field who regard themselves as both stewards, if you will, of the equipment and also do work on it. This model actually goes at the heart of that and says that decision-making needs to be separated from actual execution of work. There is a danger that field staff may adopt that too literally and will simply say I'm only going to do work if I'm told to do it; whereas clearly, they are the people in the field who probably know best what needs to be done and so you will see on Myles' model, there was that information flow back from network services back into the asset management, so in -- it's not a disadvantage in the model itself, it's in the application of the model. You have to get over that notion that information is required back by the asset manager in order to make the right decisions. And in fact, that's at the heart of this whole model. What we need is better information on the status of equipment. The danger can be that you drive a wedge in your company. Q. And did you find that was true in any of the companies that you studied, and I guess I'm also interested in understanding whether those company that you [Questioning] 263 Consultants/Board Staff looked at who have implemented this were transmission companies? I am familiar with the implementation of asset management model for the generation business, but I'm less familiar with it being implemented for transmission distribution. A. Yes. Well, one in particular gave us cause for concern, it was precisely the point I've just made. The National Grid Company in the UK adopted this model. They adopted this model back in about '93/94. And they, in fact, ended up abandoning this model. Now, I've spoken to them in detail about their experiences. It is the way the model was managed. There was -- there was a rift formed between the asset manager and the service provider that was never properly managed. They are -- every one of them that I've spoken to in National Grid said it was the right thing to do, to clearly -- the one thing you get out of this model is that it clearly identifies your costs. And they were being faced by the regulator who wanted to know precisely what the costs were of running the transmission business. In a model where everything is together it is extremely difficult to know that. When you separate out how much it's costing to make decisions versus the actual work itself, it is -- it is a much better model to put in front of a regulator. So even though they have abandoned this model in terms of how they are organized, they still have adhered to a lot of what came out of it, so they now know the unit costs which they never did before. So they [Questioning] 264 Consultants/Board Staff were universally in approval from what they got out of the model, but they felt that they -- what it was doing to the company, that was of concern to them and so they did abandon it. The other companies I know that have adopted this model have stuck by it, so it suggests to me that it was not the model itself that was at fault, but it was how it was being managed in the various companies. So we do have several other companies in Australia, New Zealand, and Boston, as I said, in the U.S. who have adopted this model, are transmission companies, and are making it work and now are showing huge benefits from it. Q. Does anyone else on the panel have anything else to add with respect to the decision-making to this or any...? MR. D'ARCEY: Yes. In addition to that, I mean, we look at it from the distribution side as well, probably the distribution side of it started its migration several years ago. We were organized into 46 area offices which were the basic little -- their own little nucleus in servicing all of the customers' needs. When you look at leveraging then, technology and maximizing your resources, you look to consolidation of those. And so that was consolidated from 46 utility -- or 46 area offices into 15 utilities, subsequently, from 15 down to 8. And then the final stage of that was down into one. And in order to do that, you leverage certain technologies such as call centre technology for the [Questioning] 265 Consultants/Board Staff billing component. You leverage a central decision-making which makes sure that your priorities for the business are addressed and not localized and they also create a flexible work force then that can be mobilized to address the work requirements where they are, not necessarily within the location itself. Q. As you were considering implementation of this model and one of the reasons you've proposed to implement this model is the benefits in terms of greater efficiencies and presumably greater cost savings. I can't remember whether we asked whether there were any sort of figures, but I'm going to ask this panel whether you can tell me in your forecasting and your budget development, where do you see and when do you think that the realization of these benefits will occur? In specific -- financial, is it 5 per cent? 10 per cent? Is it over five years? Ten years? Twenty years? How long does it take after you implement this model to see some productivity improvements in the actual unit cost numbers you were referring to? A. We are looking at it probably over the next two years to realize -- as we start to realize some of the benefits. One of the things that I can identify is facility rationalization as I mentioned to you wherein some 170 sites across the province, due to the changing nature of the business, as I mentioned to you earlier about the consolidation of the billing components within the old distribution side of it. We have facilities now [Questioning] 266 Consultants/Board Staff that no longer meet the current day requirements and we are looking to rationalize those and consolidate those to reduce the costs associated with it. We also have fleet to better utilize the fleet that we have within the two components of the distribution and the transmission delivery components pulling the forestry group together to consolidate work forces instead of being localized, so larger work forces to focus on the delivery and execution of the work has driven some efficiencies in that component, so I would say over the next 18 months as we start to reap some of the benefits of these things which we're starting to put in place. Q. Can you give me an order of magnitude? Is that 2 per cent savings, 10 per cent savings, you know, anything so we can understand how these changes that you're asking for for cost recovery through this rate application? Many of the arguments are that they will allow for future efficiencies and we don't have a sense of the magnitude of those efficiencies to understand, you know, how to evaluate the reasonableness of including these costs in this filing. If you don't have the answer now, if there's any way we can get a sense as to whether there's any quantification of the savings, that would be helpful. MR. BARRIE: A. Well, if I could -- the unit costs I think Myles was addressing. There are other cost savings, as I mentioned, just in the model itself. The most immediate ones would be the efficiency savings that [Questioning] 267 Consultants/Board Staff we're going to get from, say, the operations function. We're going to amalgamate operating incentives and have far fewer operated. So that is evident already in the Year 2000 and the major benefits will come in the immediate years following that. And in terms of reliability-centred maintenance, there is some benefit there early on, but we would expect most of that to come in the immediate years following as well, 2001 through 2003 say. In terms of percentages, perhaps we could see what we can get back to you on. Q. Yes, percentages or range of, you know, thousands of millions of dollars of projected savings, and I understand this certainly, you know, depends on things being realized, but understanding how and where the savings will occur is important to understanding, you know, why this is an approach that's reasonable. MR. HARDY: I've noted that. MS. SIMMONS: Okay. Thank you. Q. On page 31 of the transmission application, OHSC indicates that it's achieved significant cost reductions from '92 to 1997 on the order of 40 per cent and I really don't understand what's being compared there or what the cost reductions are being referred to. So I will give you some time to take a look at that, but I would like someone to comment on that statement and what it's referring to. And 40 per cent sounds like a big number to me, [Questioning] 268 Consultants/Board Staff so I don't know whether that's in capital programs, in O&M or what's going on there. And it just sounds like a big number, so I'd just like to understand, given that you anticipated that there's going to be future savings, is that a number I should look at to be obtained or realized through this new model? MR. HARDY: Susan, can you -- it's page 31 of the transmission application? MS. SIMMONS: That is correct. MR. HARDY: And do you have a paragraph or a line number that would help us with it? MS. SIMMONS: I'm sorry, it's on page 32. It begins on line 28 of page 31 and continues on page 32. MR. HARDY: So it would be line 2 on page 32, that's where you refer to the 40 per cent? MS. SIMMONS: That's correct. MR. HARDY: Okay, thank you. MS. SIMMONS: Q. It says 40 per cent in both staff and total expenditures and I really don't know what you're referring to in total expenditures? MS. FRANK: A. What we were trying to do is provide the context that one is always looking for in terms of where you are in finding efficiency improvements and we're really not at Day 1 of -- as we come forward and enter into a performance-based regulation having accomplished no improvements to date, so that's provided some context is what we're attempting to do. This truly is total cost. It's OM&A and capital [Questioning] 269 Consultants/Board Staff cost. It's the entire cost of providing the service for the transmission company. And as we've talked, I think, many times, it is difficult to have an exact trail from where we were in '92 to where we are in '97, so there is some judgment that's necessary to do these numbers. But certainly when you look at the head count that we had back in '92 and the kind of head count we have for Ontario Hydro, as well in total, you see a drastic reduction that's happened over the period. We've had many waves of people leaving our company over a series of packages. So the work is going down. I'm telling you how the numbers got in here. When it comes to the actual work and how we're doing the work differently and what we're not doing, I'll let Dave answer that. But generally for Ontario Hydro, a lot of getting the work out, getting items more efficient, less support costs, centralizing support-type costs so you don't have as large finance functions, as large HR functions and all that supporting the organization as you did in '92. We've had lots of people leaving in those areas in terms of the transmission work. MR. BARRIE: A. I think the reason these dates were quoted is, this is really the period where we possibly can provide a reasonable comparison in that there was a reorganization of Ontario Hydro around about '92 and a major downsizing occurred across the whole corporation and that model really stayed in place until about '97. So the 40 per cent for transmission will refer to what was [Questioning] 270 Consultants/Board Staff the old grid, as it was called then, and we do have numbers of total expenditures in grid and how they changed, but before the reorganization and all the difficulties as Susan pointed out, we have comparisons before and after organization. So I think the point just being made here was, that there had been substantial savings in the grid business in that four- to five-year period between '92 and '97. It is not related to organizational change-- Q. Sure. A. --this organizational change. Q. Right, exactly. Can any of those reductions be attributed to the fact that maintenance had been delayed leading to the need to invest significantly greater amounts in sustainment and development programs now? I mean, I'm trying to understand if those savings that were achieved were a tradeoff to now having to make up for things that weren't done over the last few years. Can anyone comment on that? Do you follow my question? A. Yes, I do follow the question and I agree. I believe that there is an element of that. I believe in that period, there was insufficient maintenance work being done and part of what you're saying in this program is a certain amount of catch-up. To be more specific, I don't know -- Tim? MR. DAVIES: A. Yes. A number of our capital [Questioning] 271 Consultants/Board Staff programs do reflect a condition of assets that is not influenced by maintenance. The replacement of conductors and overhead lines is very much driven by deterioration of the conductor itself due to corrosion and due to general -- loss of tortional ductility which maintenance activities do not influence, or the lack of maintenance activities do not influence. So yes, a portion of the programs are driven by perhaps catch-up and a portion of the programs are not driven by catch-up but by other factors. Q. Those elements that you just suggested with regards to that, is that simply, you know, the end of life, end of service life type of things? A. Yes, Q. Is it just coincidence that a lot of them are occurring now or could some of these elements have been replaced in the prior years and simply replacement had been delayed? A. No. I think our programs are very much driven by actual condition that we're putting forward in this submission. They are driven by actual condition, as-measured condition, not driven by age or replacement of the asset prior to the end of life. So if we were looking at the overhead lines program, this program is driven by the specific assessment of the condition of the components of the overhead line, laboratory testing of the conductor, and when the conductor is not meeting the engineering requirements through laboratory testing of samples of the [Questioning] 272 Consultants/Board Staff conductor, then we're putting it forward as a circuit that needs reconductoring. Q. Then maybe this follows on to my next question which was a statement that was made on page 73 of the transmission application. There is a statement here with respect to the transmission stations which begins on line 11 towards the end and continues on through line 13. It indicates a large number of stations were built in the 1950s and consequently, many components are reaching the end of their life and require refurbishment or replacement. Is this true of your stations as well? Is it the conditions or is it the end of life or is it a combination? Can you help me understand? A. Well, I think the only benefit of age is to give you an indicator of where to start looking at the actual condition of the assets, so if your expected life of a particular asset, say, is 50 years, you don't go out and measure its condition if it's only five years old. So that may be stating the obvious. In one of our submissions - I think it's appendix D, which is a strategy document, transmission component refurbishment or replacement, page 40 of that, it's Appendix 1, talks about our expected service life of those particular components. So for example, our expected service life of a power transformer is between 40 and 55 years. Our expected life of insulators is 60 years; shield wire, 45 years. [Questioning] 273 Consultants/Board Staff Now, our actual experience varies depending on the circumstances. Shield wire, which is galvanized usually, is influenced by atmospheric pollutants - it corrodes. Depending on the areas of the province, we have had shield wire that is in the failure mode as young as 25 years. We also had shield wire that lasts more than 65 years. So when we're putting forward programs for replacement of shield wire, we are actually doing laboratory tests on samples of that particular shield wire before we're proposing to replace it. Q. So is it accurate to say that certainly age is a driver; however, it's the actual condition which is going to determine replacement, repair, refurbishment, whatever needs to be done? A. Age is an indicator to us to do a detailed assessment of that particular component, but it does not drive us to replace it. It's an indicator for us to go out and look at it carefully. Q. Okay. Another general question - I'm trying to keep them general and let me know when we want to break: There is some discussion with regards to the new transmission operations management centre at Richview. I would like someone to comment to please help me understand how the decision was made to design this new centre and what sort of feasibility and desirability this particular centre has with respect to the -- I understand it will achieve efficiencies over the existing four centres, but [Questioning] 274 Consultants/Board Staff if you could just kind of expand upon how this decision was made, why Richview, what specific benefits will be obtained as a result of this centre? MR. HARDY: Are you referring to the statement at the bottom of page 73? MS. SIMMONS: Yes. Q. And the Richview Centre appears at various places, but it also is, I believe, first referenced at the bottom of page 73 on line 17 and appears in various other places in the filing. MR. BARRIE: A. I wonder if it would help if I gave a brief review of how operating takes place? Q. It would be helpful to understand how it's being done today-- A. In the context of your question. Q. --relative to some of the other systems I'm familiar with, so this would be helpful. A. Okay. As I mentioned, the CMO, as we call it now, and the IMO, as it will be called, really has two functions: to operate the market and to direct transmission operation. As I mentioned in my presentation, they don't have any physical hands-on control from there at all. And in terms of system operations, it's important to understand what the IMO's focus is. They're looking to maintain the overall security of the bulk transmission network. That's their No. 1 priority. We currently have four electrical area operating [Questioning] 275 Consultants/Board Staff centres and the proposal is to amalgamate those four into one single transmission operations management centre who would take direction from the IMO but whose functions are very different from the IMOs. Of course, the TOMC is like the IMO, interested in maintaining the integrity of the overall transmission network, but the focus is a lot more on the supervision of the actual assets, so things like - and I've listed a number of them down the right-hand side there - but things like optimizing the way we do outage management on the system, for instance, would be something we're looking for the TOMC to supervise on behalf of myself acting as the asset owner. So in my view of the world, the transmission operations management centre provides real-time asset management. So there's a decision to be taken on the asset right here and now at three o'clock on a Sunday morning. The TOMC will do that on my behalf given -- and he will get certain directives and policies and procedures as to how he should do it, but that's essentially how we see the TOMC. On an ongoing basis we would see him helping in this contract compliance; that is, we are going to have all of this work going on out there. The operating group, or one of the key groups can keep me, as an asset manager, informed as to how things are going on the various contracts we have out there. So again, I see the TOMC helping me in my asset management. The group at the bottom are the hands-on [Questioning] 276 Consultants/Board Staff operating centers and right now, as I've said, we have 17 of those and that's coming down to 10 and could possibly come even lower. They actually have the physical capability to open and close switches, to tap change, to do all the other things that you do to operate a transmission system. They also have a critical role to play in work protection administration so anyone working on equipment looks to the operating group to ensure safe working conditions before work is allowed on equipment. So that's a critical role for them as well. We also do provide some direct customer interface. When a customer's lights go out, normally the first people they call -- well, if they are a sophisticated customer they know who to call to get the real situation, and that is the local operator who probably knows more than someone sitting in head office. Now, the decision, as I said, was initially driven for the TOM Centre on straightforward economy. It's just cheaper to do it at one place than it is at four, and we now have the technology that allows us to do that. Right now, because we are all part of Ontario Hydro, my TOM Centre does rely on information being passed to it from the CMO, but in future, when we are a completely separate company, we are asking ourselves the question right now: "Do we need to have our own data gathering?" because there's real time information coming [Questioning] 277 Consultants/Board Staff into this place. We are pulling the condition of the transmission network every two seconds to know what's going on. And we may have to have our own method of knowing exactly what's going on on the system, separate completely what from what the IMO has. Now, how this compares to other places, this is typically what happens. So if you look, for instance, at New York state, they recently initiated New York ISO, will be equivalent to our ISO, but ConnEd will still have its own operation centre equivalent to our TOMC. So I see this as being quite consistent with what's going on in other utilities. We have put a skeleton facility in place right now at Richview. We are in the process of amalgamating two of the four as we speak, and in fact, by the end of January, I should have all of southern Ontario supervised from Richview. The northern Ontario will take a little longer. We haven't spent very much right now and we need to -- we need to put more facilities in there and that's the essence of what's in the capital program. Does that help at all? Q. That helps. Can you address the question as to why didn't you just expand one of the existing four centres; why did you create this entirely new one of which the four will be amalgamated into? Was there something about the location-- A. Yes. Q. --of this relative-- [Questioning] 278 Consultants/Board Staff A. Yes. Q. --to the four being interdispersed? A. Well, that's very interesting because we almost did exactly that, in fact. One of the four is at Claireville which is only about 10 kilometres from Richview, and so we did have quite a good look at what we could do at Claireville. And it was really just the physical limitations of what we have at Claireville and what we were capable of putting in at Richview. At Richview we did have a control room already under way there for another purpose than we decided to make our TOM Centre, so it was really the efficiency of doing it there, really. There's no magic about that particular place, and it could easily have been at Claireville. I wanted it reasonably close to Toronto so I could get there if I wanted to. But it really could be anywhere, quite frankly, anywhere that was a communications hub could be the TOMC because at the heart of TOMC is, of course, communications. Q. And one more question and then it would be probably a good place to break. What's going to happen to the other four centres? Are those properties going to be abandoned in place or are they going to be converted for other use? A. Well, they are all at transmission sites. They are actually buildings right in a site-- Q. Okay. A. --so it's not like we have some spare land at [Questioning] 279 Consultants/Board Staff all. We probably have a room that would no longer be utilized. Q. Okay. A. So I'm not sure what we are going to do with them, but it's not a big windfall by any means. Q. I'm more concerned with what may be left over that may be recovered from those places. A. Oh, not a lot. Q. Okay. MR. HARDY: I'm going to break here. I've got 10:20 on my clock, so come back about 10:35. At that time I'm going to try to take a couple questions from some participants as well and then we'll move back into Board Staff and Consultants, okay? So we'll see you back here at 10:35. ---Recessed at 10:20 a.m. ---On resuming at 10:35 a.m. MR. HARDY: Okay. I wonder if we can take our seats and we can begin this next portion of the session. Thank you. I want to begin by opening up questions from participants and then we'll move back into Board Staff and Consultants. Mr. Gibbons, I believe you had a question or two that you wanted to ask at the outset? MR. GIBBONS: Yes, thanks. I'm Jack Gibbons from Pollution Probe. Q. I would like to ask you a few questions about your proposals to increase your transmission capacity of [Questioning] 280 Participants neighboring jurisdictions. I believe that the capital cost of the Michigan/Ontario phase shifters is $33-million, and by how many megawatts will that increase your interconnection capacity with Michigan? MR. BARRIE: A. Because of the nature of that particular interconnection, it will allow some 500 megawatts more import and 1,000 megawatts more export. Q. And the capital cost of the Quebec/Ontario high capacity tie is $44-million; by how much would that increase your interconnection capacity? A. 1,250 megawatts, either import or export. Q. Okay. And I believe you are also planning to increase the capacity at Niagara; is that true? A. One of the -- this is an internal interface which limits interconnection capability. The Queenston flow west interface, as it's called, and that is the particular one you're referring to, and that is a later capital plan we would expect to implement in following years if further interconnection is required. Q. So what year will be the earliest year for that, then? A. I had better defer to Bob Chow at this point. MR. CHOW: A. We will be initiating some of the project development work in Year 2000 with an in-service date of about 2003. Q. Okay. And what would the total capital cost of that project be if it goes ahead? A. Roughly it's about 120-million. [Questioning] 281 Participants Q. And how many megawatts of increased capacity would that give you? A. It will increase the interconnection from the Niagara area about 800 megawatts. Q. For exports and imports? A. Mainly for import. Q. Oh, so it increases the import capability by 800 megawatts, and how much does it increase the export capability by? A. Again, Dave had mentioned, the problem with that is not interconnection itself, not to increase the interconnection in Niagara. What we are doing is we're moving an internal restriction to obtain the full capability of the Niagara interconnection. So what you're doing in this particular case for the Niagara area is the problem is power coming into Ontario because it supersedes, it moves on top of power flows coming out from generation at Beck so the sum together, the issue here is really the summation of the power sources coming from the Niagara area into the Toronto-Hamilton area. Q. So this project will not increase our capability to export power to the United States; is that what you're saying? A. Currently, there is export capability and I think one thing that is kind of complicated in the interconnection area is that the import does not necessary equal export, but obviously, directionally, if you increase transmission capability, there will be benefit in [Questioning] 282 Participants the opposite direction. Q. And can you quantify that? You quantified in terms of imports will increase the capability by I think 800 megawatts you said, and then exports, can you quantify the increased capability? A. I think all you can say is that the -- it would not increase it beyond the capability of interconnection itself. The export capability is still limited by the interconnection. MR. BARRIE: A. Could I just try and help out a little here? Q. Okay. A. Because of the configuration of the generation and transmission in the Niagara Peninsula, this particular limit normally has no bearing on our export capability. We have a large amount of generation actually right at the border, so when you're in a major exporting situation there, you're exporting basically the Niagara generation. So there is very little flow internally on this particular interface. So I think really the short answer to your question is, this expenditure does not, in practice, increase our export capability. Q. Okay. Thank you. Now, as you're well aware the Market Design Committee has recommended that Ontario Hydro Services Company increase their -- or expand their high capacity with neighboring jurisdictions by about 2000 megawatts [Questioning] 283 Participants within three years. And we've gone over three projects just now in our little discussion and we've talked about the amount of increased megawatts and we've talked about the capital cost. What we've talked about so far, do you believe fully complies with the MDC's directive? Is that all you have to do to comply with the MDC's recommendation? A. Well, if you take the first two leaving aside the Niagara for the moment, and you add up the numbers I just gave you, you would get 1750 more import and 2250 more export, so I think that, in spirit, complies with the directive from the MDC and the Cabinet. Q. Okay. A. It's not completely, but it's in spirit, they're there. Q. Right. And this increases the amount that you can import at the border, but presumably I guess the MDC wanted to -- the reason for this increased capacity was to make it more of a competitive market and I guess that means to have more power available from non-Ontario sources in key areas like the Golden Horseshoe and the GTA. Now, to actually -- to bring that extra 2000 megawatts to the Golden Horseshoe or the GTA, would you also have to make additional expenditures to increase your transmission lines? I mean, is it -- can you not just simply stop at just increasing the transmission right at the border points, do you also have to bring -- build in [Questioning] 284 Participants extra new transmission lines too? A. Okay. You brought your -- a very critical subject because it is not simply a matter of increasing the interconnections; in fact, all of the numbers we quote are based upon the practical limitations of simultaneous import or export. If you add up all the numbers of our interconnection capability, you'll get a much higher number than we quote as our capability because you practically cannot do that for the very reason you've just quoted. In the particular ones we've spoken about, one would have to postulate where the imports and exports were coming from or going to. So in the case of the Quebec one, it's fairly straightforward. It's a 1250 megawatt either import or export into the Ottawa area. We do not envisage any requirement to upgrade the 500 kV into the Ottawa area to cater for that. In the other case, both capabilities we feel require no major upgrade internally. So having said that, I'll defer to Bob to give you specifics. MR. CHOW: A. Well, Dave is perfectly correct. We have no plan beyond those identified for the purpose of import, for bringing that level of import into the system. Now, this is assuming that, in general, the system basically is centred at Toronto, let's say, so the Toronto area carries a strong transmission system. So once you get into the main backbone of the system, which is to find the kV system across basically [Questioning] 285 Participants from southwestern Ontario across to Kingston, you pretty well plug into the main part of the system. The difficulty is that you are looking at historically how the system was developed, you basically incorporate internal generation to serve the main low centres. So the transmission that tie the internal transmission to low centres is very strong. We never really in the past have provided that kind of strength to the interconnection points. There's no final kV per se that goes straight to the interconnections. So a lot of it is now linking that part of the system into the main grid. Q. Okay. So we are focussing at the Michigan and the Niagara proposals. And you've given us the information about how much that would allow us to increase imports and you have told us the capital expenditure. And so that is enough money and enough activity to actually allow that power to come into the GT area and help create a competitive market in the GT area by that number of megawatts that you're increasing the capacity at the border? A. Yes. Q. Okay, thank you. Now, with respect to each of these projects, do you have a forecast of the increased exports and the increased imports that you're assuming will occur at each of these interconnections over the next twenty years, say? [Questioning] 286 Participants MR. BARRIE: A. No. Q. Okay. Have you done a cost/benefit analysis of this proposal? A. From a transmission perspective? Q. No, from a financial point of view. I'm trying to figure out whether this is going to push up rates for Ontario customers. Have you looked at -- you've told us what the costs are going to be, at least the capital costs, and I'm just looking at what will be the incremental revenues and try and see what the incremental revenues on discounted net present value basis will exceed your costs over some reasonable period of time? MR. CHOW: A. Like I say, the project that we have looked at is looked at in terms of the lowest cost per kilowatts serves for import purposes. Now, being for import purposes we hope that will stimulate the market and allow the energy price to be more competitive. So the gain to ratepayer basically in Ontario is from a lower energy price through the competition. Now, in terms of the impact on the rate, of course there will be an increase because of the capital cost basically on the transmission rate. We believe the costs of those projects that we quoted are the lowest one that permits you to achieve the objective through the MBC and the government in providing interconnection capability to stimulate the market. [Questioning] 287 Participants Q. Okay, I understand that. Are you planning to do an analysis to figure out whether it passes in terms of a net present value? I understand the rationale for it. It's the lowest cost way to meet the MBC's recommendation but are we going to have a net present value analysis of the cash inflows and outflows to see whether it will actually push up or reduce transmission rates? MR. BARRIE: A. I think we've got to establish what we are is a transmission company. It is not our business to try to assess how the market will respond. We've been given a directive to encourage the market and we believe we've got the cheapest way of encouraging the market. As far as we're concerned that's the end of our accountability. Q. Okay. I mean, I'm just used to dealing with the gas utilities here in Ontario and, for example, Union Gas is a major transmission company and they often come before the Board to increase their Dawn-Trafalgar transmission line. And again in that sense they're just a transmitter, they're transmitting other people's gas, but every time they come before the Board they have to give a financial cost/benefit analysis comparing the revenues and the costs of that project and the revenues or their increased transmission totals against their costs so the Board can figure out whether this is a winner or a loser from a financial point of view. But I guess what you're saying is you're not [Questioning] 288 Participants planning to provide that kind of an analysis to the Ontario Energy Board? A. Well, my understanding of the way the transmission rates will be charged is that the native load customers will be picking up the transmission charge. Q. Right. A. When we put in extra capital for this kind of thing, an interconnection, in terms of extra revenue coming in, I don't see additional revenue other than it's going in the rate base, but all the customers are benefiting from the fact that there is now a better market operating. Q. Okay. Have you tried to estimate how much they'll benefit in financial terms from a more competitive market, how much this increased competition will push down rates to compare that with the capital cost of the new capacity? A. No, I have not. MR. HARDY: I guess I'm hearing the question asked two or three different ways and I'm hearing the response I think clearly from the panel, so I'm not sure if there's another direction you wanted to take that particular question but certainly I'm hearing the panel say that they haven't done that calculation. MR. GIBBONS: I know, sir. I'm hearing that too. I'm just a little bit surprised so I just asked it more than once just to make sure I've heard it right because it's such a huge disconnect from what I'm used to at the [Questioning] 289 Participants gas side so I just want to make sure I'm hearing right. MR. HARDY: So perhaps you can move on. MR. GIBBONS: Oh, yes, sure. MR. BARRIE: Could I just add one thing about the particular installation at the Michigan end? We were considering this long before this particular directive came out and that is because this particular installation helps to inhibit flow through our system caused by other people's transactions which had got so bad at one point last summer that it was actually threatening our ability to satisfy native load, our own load. So this not only allows a better marketplace, but it actually improved the security of supplies to Ontario customers. I can get into that in more detail if you wish but it does have a security spin to it as well as a marketplace spin. MR. CHOW: I just want to add to that, of course, is that a lot of the proposals we have on the interconnection improvement, especially in Niagara, is to try to get the capacity that's already built in the connection to realize it. Over the year because of changes on the system cause an inability now to use it. Like Dave said, due to external influences through loop flow the system we, in fact, are losing a lot of capability. It's almost like you're moving a step backward before you move forward. That's where we are today. [Questioning] 290 Participants So when they flesh-up their project is just try to gain back some of the capability we have been losing over the last five, ten years. MR. GIBBONS: Q. Thank you. With respect to the imports and exports, you don't have a forecast I believe of the total amount. Do you have any forecast of what will be the generation source for the imports or exports? MR. CHOW: A. Well, I mean in the case of Quebec it's kind of obvious, it's hydroelectric power from Quebec. Q. Would it not be possible to wheel power up from the United States and bring it through Quebec; is that not a possibility? A. Anything is possible. It's unlikely, the situation with Quebec being the producer. In the U.S. market it could be anything, could have new generation coming in, could be gas, could be the old generation. So really it's a free market. Q. Right. And you don't have an estimate of what proportion is likely to be gas or coal or nuclear or wind? A. No. Q. Okay. And in terms of regulatory approvals for these projects, I would just like to go through what are the regulatory approvals necessary in your view. Now, you bring it before the Ontario Energy Board in this sort of rate case. Now, are you also planning to [Questioning] 291 Participants seek approval from the Board for this in a facilities case, a separate facilities case? MR. BARRIE: A. For which one? Q. For all three of them, any one of the three? A. Clearly if an environmental assessment is required for the actual physical facilities, and that would be the case for the Quebec one-- Q. Right, okay. A. --then we would have to go through whatever the requirement is. Q. Are you talking about an environmental assessment hearing? A. Yes. Q. My first question was about an Ontario Energy Board facilities case. I guess I'm going back to my sort of gas knowledge. When Union Gas comes forward with a transmission proposal they notify the Board in a rates case and it's taken into account but they also have to go forward in a separate facilities case which looks at the cost/benefit and the environmental impacts of that specific facilities application. And I believe there's provision under the new Act for facilities cases for electricity transmission facilities and I'm wondering if you're planning to seek the OEB's approval in a specific facilities case? A. We're in transition right at the moment, of course. We will follow whatever the law of the land is at [Questioning] 292 Participants the particular time that we're at. Right now in the case of Michigan, for instance, we were required to get our own Board approval and because it's all on our property we could move ahead with that. We're now in a position that I'm not sure what the position is going to be between April the 1st when OHSC becomes a separate legal entity and the actual opening of the market which is July 2000, but whatever the requirement is at any given time we will follow the requirements of that. And to be quite frank, I don't know precisely what that will be. MR. GIBBONS: Maybe your counsel can help me out now. Do you believe you need OEB approval in a facilities case? MRS. FORMUSA: Right now section 92 of the Ontario Energy Board Act has not been proclaimed in force. When it's proclaimed in force, then obviously transmitters and distributors have to comply and we will be one of those and will comply with section 92. MR. GIBBONS: Do you have any forecast of when that is going to be proclaimed? MRS. FORMUSA: No, I don't. MR. GIBBONS: Okay. Q. Well, then talking about the Environmental Assessment Act in Ontario, do you need to get approval under that Act? MR. CHOW: A. For the Hydro-Quebec interconnection we are proceeding very soon with a Class [Questioning] 293 Participants EA which that type of project is classified under. Q. What about the Michigan and Niagara ones? A. That one is just involved in storing equipment at our own station, mostly at Lambton, so that's exempted. Q. Exempted. And what about the National Energy Board? A. The one with Hydro-Quebec, the Hydro-Quebec people are leading that effort because it does involve a crossing of the Ottawa River so we'll be participating in it but they're taking a lead in it. Q. What about the Michigan and Niagara, do they require National Energy Board approval? A. No, they don't. MR. GIBBONS: They don't? Okay, thank you. Those are all my questions. Thank you. MR. HARDY: Are there other participant questions? MR. ROBERTSON: Ed Robertson representing OCAP. Q. I've got a couple of questions. The first one is directed to pages 7 and 8 of the handout we got this morning entitled "Transmission Assets and Capital Plans" Panel. It seems to me and I look for some either confirmation or otherwise from the panel, that one message one can take from these two charts together is that -- in fact, I really ought to include the three in a row. In other words, I'm looking at projected expenditures, page [Questioning] 294 Participants 7, and the combination of the two charts which follow showing cost and reliability concerns. What I'm really trying to find out is, is it a reasonable expectation, looking at the two bar charts, to say that they're interconnected in the sense that the low cost perhaps is a result of the high unreliability? Is that a reasonable assumption? MR. BARRIE: A. I don't want to suggest there is a direct one-on-one correlation; however, there is certainly a relationship between how much you spend on your transmission system and how reliable it is, yes; however, having said that, I can't divulge who all these people are in these other things, but it would not be true to say that the lowest cost was the worst reliability and so on, but there is, broadly speaking, a relationship between cost and reliability and as long as you take it in that general sense, I would agree. Q. Yes. I wasn't looking for any one-on-one relationship. That would be nonsensical. But it just seems to me from a commonsense point of view that going on from your confirmation, there is some sort of relationship... A. Could I just add my other caveat that I made in the presentation? Q. Mm-hmm. A. Almost regardless of how much sustaining capital we spend here in Ontario, because of the configuration we have, particularly in northern Ontario, [Questioning] 295 Participants we would never get to the good end of the scale unless we actually spent hundreds of millions of dollars to reinforce northern Ontario. So the very nature of our system means we can never be highly reliable, but we could certainly move in that direction. Q. Yes, I take that caveat and I understand its significance. Moving slightly on from that question, is it another reasonable assumption to say that the difficult conditions that Ontario Hydro have experienced in recent years, and most of us here have seen them one way or another, perhaps are responsible for the, let's say, underexpenditure in what might be required technologically for strengthening of the transmission system? In other words, have you been styled in the difficult economic circumstances that Ontario Hydro has been in in recent years? A. Well, I think in response to Susan's question earlier, I did indicate that I did feel there was some correlation between underexpenditure and I believe we have been spending too little on the transmission system in the last five years and that performance, but it would be unfair to lay all of the claim there, because as Tim rightly pointed out, we are facing an aging population of equipment that we would have had anyway, so it's partly true, yes. Q. Yes. Well, I was going to refer actually to the aging thing and the -- I mean, if, in fact, you are in [Questioning] 296 Participants a situation where you have a list of aging and possible reliability -- unreliability associated with that, the temptation I would have thought in a particular squeeze, and I've been in that situation, is to say, well, it will do for another year and that's not to the taste of the technicians and engineers involved. There's usually an uproar when that kind of thing comes down from the top and through financial rigour, but is it reasonable to assume you have been exposed to that kind of stuff in the last few years? A. Yes. Q. Moving on then. My second question is: I'm interested in the notion of the service agreement which is, it seems to me, part and parcel of the asset, the proposed asset management system. What happens if there's poor performance or limited performance on the part of the service provider within the context of one of these contracts? A. Well, we have to be clear that we've just started this process, so I really do not have experience yet in poor performance on an SLA. All I can say is that we are monitoring the performance of the service provider against our expectations as laid out in the SLA. As to what the repercussions would be for poor performance, I have no experience of it yet. Q. Well, I can't take your assurance you're thinking about it in discussing the form of the contractual relationship, say, with company legal staff [Questioning] 297 Participants because a contract is a contract and it's got to be enforceable on both sides I would say. A. Yes. Perhaps, Myles, do you want to ...? MR. D'ARCEY: A. Yes. If I could just add to what Dave has commented. This is the basis for commercial relationships. It formulates what would be required between the two halves of a company in a formal arrangement. To that end, there is no penalty clauses in between one side of the business and the other. It would not be prudent to have penalty clauses within it. What we have is our putting linkages between the manager's performance in the excecution of those SLAs so that the managers pay as is directly related to their ability to meet those requirements. MR. ROBERTSON: That's a fair answer, thank you. I have no more questions. MR. HARDY: Other questions? MR. STEPHENSON: Richard Stephenson for the Power Workers' Union. Q. Let me come back to the SLAs for a moment. In terms of the transmission agreement -- or sorry, the business, who are the parties just typically or by way of example on an SLA? Who is on the other side of them and -- on each side rather, I guess? MR. D'ARCEY: A. Typically, the asset management group is on one side. The decision-making body who would hold the asset has a requirement for particular work to be [Questioning] 298 Participants done and then the service provider is on the other side of that and in this case we'll quantify it as network services. We have then within OHSC divisions between transmission as an asset management group, distribution as an asset management group and also within our retail, what our retail merchant or customer service class for a component such as water heater maintenance. Q. I'm assuming that on a particular SLA, within network services, there will be some either regional or divisional or some subset of network services is the contracting party on it or is it just network services, period? A. It's network services for the delivery of that product to service in the province of Ontario for the asset management group. There is no localized component now. Q. Do you have any kind of without -- I don't want anything with numbers in it, but do you have any kind of a draft SLA that you could provide to us that shows us the form, format, kind of standard provisions, that kind of thing? A. We have as mentioned developed SLAs. There are some commercially-sensitive components because not only are our prices internal for the asset management group in the provision of a product or service, but there's also similar pricing related to it, an external component which we also have as well. [Questioning] 299 Participants Q. But nobody wants to see any numbers and indeed, is it -- whether it's possible to redact anything in your discretion which you consider to be commercially sensitive and give us the rest; can you do that? A. Yes, we'll look at it and see if there's an opportunity there. MR. HARDY: Okay, I've noted that then, and I assume you'll block out anything that's commercially sensitive and so on. MR. STEPHENSON: Q. On the interties question for a moment. Obviously a potential intertie location is the Manitoba/Ontario boundary. I assume that there's -- because of the limitations of the northwest area, there is limited value in pursuing those at this time? Is that -- what's the -- what are the considerations that apply in exploring that as a potential capital investment on interties? MR. BARRIE: A. Well, I think you almost answered it yourself. The limitations of the northwest Ontario transmission and the sheer distances involved, in order to make -- in order to get Manitoba generation to the main load centres involves huge distances and would be hugely expensive. In fact, a few years ago, Ontario Hydro was looking at that very proposal and I think the number was $2-billion at that time. To simply reinforce at the Manitoba interconnection doesn't get you anything because there is a limit from the northwest into the rest of Ontario that's [Questioning] 300 Participants 2- or 300 megawatts. So you actually would have to build right from the Manitoba border, in fact, beyond the Manitoba border right into 500 Kv network. So it's really -- it comes down to geography and the associated cost. Bob, do you want to add anything to that? MR. CHOW: A. Yes. In fact, the strengthening of the Manitoba tie and east/west tie has been looked at for years, tens of years, and the kickers always have been. It costs close to billions of dollars just to link the two between Thunder Bay and Sudbury and maybe even further south. So I don't think I need to reinforce was Dave has answered. It really comes down to the economic. Q. Just in terms of the northwest system as well, in terms of just servicing the energy needs in that area I take it, is there any transmission limitation between Ontario and Manitoba in terms of servicing those local customers in Ontario in the northwest area? A. Currently, there's quite a lot of -- an extensive amount purchased from Manitoba right now up to the intertie capability with Manitoba. So, in fact, the northwest now is a net surplus area in terms of power, the power it could use if you just look at it from the context of northwest. So most of the energy are being exported back to Sudbury and the Toronto area in excess of its need. MR. STEPHENSON: Thanks, those are my questions for now. MR. HARDY: Thank you. [Questioning] 301 Participants Are there other participant questions? Ken? MR. SNELSON (AMPCO): Okay. Can we just start with the clarification of one of the charts you gave us this morning which I found very interesting and that's on -- it's the chart "transmission O&M and CAPEX per megawatthour kilometre" which is quite a mouthful. I presume it's page 8. It seems not to be numbered, but it's after page 7. MR. BARRIE: A. Yes. Thank you. Q. And I would like just a bit of clarification as to what the index means. I think I understand the O&M and I think I understand the megawatthour kilometre. Now, the CAPEX factor was said, I believe, in your presentation to cover capital, and I'm just wondering how capital is included in this? Is the capital expenditures each year included with the O&M or is this sort of a carrying cost of capital or how is this handled? A. Yes, Ken, it's actually the capital spent that year, so what it doesn't take account of is previous capital. Q. Okay. And I believe this was 1996? A. Yes. Q. And as proposed in this proceeding, both the O&M and the capital are considerably higher than they were in 1996? A. Yes. [Questioning] 302 Participants Q. And so it's quite likely that Ontario Hydro doesn't rank quite as well -- or SERVCO, based on the numbers in your submission, would not rank as high as shown in this chart? A. Yes. In anticipation of that question, I did do a rough calculation of where we would be if we injected 1999 costs and left all other participants as they were. We'd move up to the right by two or three places there. So actually, in the big scheme of things, it's not a significant move, but it's -- you're certainly right, it does move us to the right here and it moves us out of what I would call first quartile into second quartile. Q. Okay, thank you. I had proposed to ask some questions with regard to sustaining capital which you've answered to some degree in your presentation this morning and I was going to cover the degree of increase over the past spending which is covered on page 7 of your handout from this morning and you show the 1998 number for comparison and for sustaining capital, I believe that's about $120-million approximately looking at the figure. I had taken the information that you've provided under tab "I" of the supplementary filings where, for all of the sustaining plans, you had given a five-year average for pre-1999 and I could find all of the sustaining programs except for the Pickering switch yard's component which may or may not have a pre-1999 component, I don't know. Is there a pre-1999 component for that? [Questioning] 303 Participants MR. DAVIES: A. The answer is no. Q. Thank you. And on that basis, I found that the average for pre-1999 expenditures on sustaining capital was $119-million which is very consistent with the figure that you've given for 1998. So that confirms that your proposal is a significant increase, not only over 1998 but over the previous five years. And on that basis, according to my figures, 1999 is an increase of about 49 per cent and 2000 is an increase of about 71 per cent. And you have acknowledged that although the system is getting old, then the performance trends shown in the charts on pages 54, 56, 58 and 61 don't show a declining trend and your position is that the reason for the increase being required is the asset inspections and that that is showing a condition which you believe to be precursors of poor performance. Now, the first question - having gone through all that quite quickly - the first question additional is, well, the asset inspections you referred to started in 1997 but I don't believe that Ontario Hydro has not been inspecting its assets on a continuous basis over many years and was not aware prior to 1997 that condition was deteriorating. And to that extent perhaps you could comment on the degree of increase at this particular time and why that was not included in the 1998 business plan that was approved by the Ontario Hydro Board of directors just last year? [Questioning] 304 Participants MR. DAVIES: A. Perhaps I'll make a comment on one of your first statements that overall system performance is not deteriorating. I would be the first to admit that historically we have not done a good job at recording the reliability of individual components. The data that we do have tends to be around the performance of transformers, switch gear and lines rather than the performance of the many other supporting components that build up the system. The data for transformer lines shows that the forced outage rate, the occurrence of forced outages of lines is deteriorating for the 115 kV circuits and not a minor deterioration but the 115 lines are substantially deteriorating in terms of the individual circuits forced outages. Transformers and switch gear is approximately flat. I think the answer to your main question of why wasn't this recognized in the past I think Dave gave to the other gentleman when he asked about the emphasis of the corporation in the past when it was looking at capital expenditures. In other words, it was not placed as high a priority as other issues that the corporation was facing for capital expenditures in the past. Q. Okay. And moving on then to the development capital, and this is kind of a detail question, but if you turn to section I of the supplementary material and on [Questioning] 305 Participants page 39, there is a description of the capital plan to improve wholesale metering to meet MBC requirements? A. Yes. Q. And my question actually relates to the very bottom box of this page when refers to a Development Capital Reference Plan and I wonder if you could tell us what is in that and whether that has been made available to this Board in this proceeding? MR. CHOW: A. I think it's just the timing of the process, the time just before the filing that particular item there on the improved wholesale metering was not part of the plan so it was added in just at the very late stage of the preparation for the OEB. When we did our reference plan which is basically the submission you see other than this one item, that is the reference plan. Q. So you're saying really there isn't a separate plan that will give you us more background on these... A. No, this is the same plan. Q. Is it possible -- we've talked about the increase over the '98 business plan and this is for all of the capital programs, sustaining and development transmission and supporting capital programs, can you identify which capital programs are in the plan now but were not in the 1998 business plan that was approved by the Board a year ago? MR. BARRIE: A. We'll have to take that up, Ken, [Questioning] 306 Participants and see what we can do with that. I mean I can't right here and now. Let me see what I can do. Q. It just seems to me that it's an important consideration in looking at what has been added, what's now considered affordable that wasn't considered affordable and so on? I've noted that, then that there may be something, a response. A. Can I be specific? Ken has asked what plans were not included in the '98 that was approved by the Board that are in here now. Because clearly any increase in costs will be due to two factors: They'll either be new plans or there could be an increase in a previously approved plan? Q. Yes? A. Do you want both? Q. Yes. A. All right. Q. We also come back to the issue of the writeoffs that were made in 1997 and which were made for non-nuclear purposes and last week we discussed that and there were items of $830-million and $147-million included as non-nuclear items in those 1997 writeoffs and the question is: Are any of the capital costs that are part of those items that are being put forward in this proceeding, are any of those capital costs items that were written-off or made provision for in these writeoffs and you're now intending to charge them to customers? [Questioning] 307 Participants MS. FRANK: A. The writeoffs that you're referring to Ken were the provisions we made in 1997 for primarily OM&A expenditures so that when we talk about our OM&A program tomorrow, we will talk about some of those expenditures. The only portion that was related to capital was a small amount of writing off of some buildings that we're no longer using and they were taken care of back in '97 so there were some field locations where we would have had an administratively building that we wrote off. There weren't actually capital program expenditures as part of piece. Q. Okay. One of the reasons for the writeoffs, one of the aspects of the writeoffs was ice storm damage? A. Yes. Q. And several of the capital programs show as part of their rationale to rebuild after the ice storm, the one that comes particularly to mind is on page 50 of the supplemental information under tab "I". A. Ken, the writeoffs were OM&A expenditures. They did not include the capital program. So the capital expenditures are in here and you referred to page 50 that describes that program but it wasn't included in the provision. It was only OM&A expenditures in the provision. Q. Thank you. Because that one particular one particularly references the ice storm rebuild but that you're saying is separate and additional? [Questioning] 308 Participants A. We had two items that we dealt with in terms of ice storm. There was work that was really going out and getting people back on-line and were not putting in a new asset and those were OM&A expenditures and we made the provision for that. And then there's the actual building the asset that's down on the ground and obviously Bob would talk to that if you wanted to know about the L1MB line in particular. But that was not in the provision. Q. I have just a couple of questions with regard to the interconnections. Some of my questions have already been asked. The first question is just a straight technical question for my own curiosity as to where you're placing the phase shift within the system? Are they being placed in all the interconnections between Ontario and Michigan or just some of the interconnections between Ontario and Michigan? MR. CHOW: A. The phase shifter -- basically there's a phase shifter on the every intertie line going to Michigan. What you're trying to do is to control a loop coming into New York going out of Michigan. You can control it at any part of the loop. You can control it at the Niagara point if you wish. But you have to control every -- basically every path that flows through that particular interconnection. The economic place to do it is at Lambton with [Questioning] 309 Participants the Michigan interface and also at the Sarnia area basically covering all the interconnections. Currently there's already a phase shifter down in the Windsor interconnection. Q. I'm just curious as to why this only gives limited control over the loop flow and doesn't provide you with complete control over the loop flow? A. Just the physics of the ability to control that amount of power using phase shifters, you just don't have total freedom to control all the flow. Q. Is this a limitation on the angle that the phase shifter can shift the power flow through? A. Yes, they're not basically 360 degrees. If we were willing to spend a lot of money on a BC connection, we could control everything but that would be many, many times the cost of this. Q. Under your Other Improvements, under this is the St. Lawrence to Quebec improvements which are on page 59 of tab "I", and this program is not enormously expensive but this program is to facilitate the connection of generators at the Saunders Generating Plant directly to the Hydro-Quebec system to allow the transfer of energy to Hydro-Quebec; is that correct? A. As we indicated the Hydro-Quebec connection is not synchronous to Ontario. So whenever we have to interconnect and transfer power, either they isolate generation to us or we do the opposite way. In this particular case the use is for banking of [Questioning] 310 Participants power from Ontario and Quebec to optimize the use of the resources. To do that on a return banking arrangement where we send power to Quebec, we have to isolate basically most of the Saunders Station at St. Lawrence to the Quebec system during the time that we are pushing power into Quebec. It's very cumbersome to do so today and the number of units you could do that is also limited. The purpose of this plan is to speed up the process of connection which could take many, many switching operations and wear and tear on the equipment to reduce time and also increase the ability to isolate almost half the units at Saunders to Quebec to allow a faster delivery of energy to the Quebec site. Q. Now, the generators in the new scheme of things, the generators at Saunders will be equipment belonging to SERVCO. The energy that is being transferred to Quebec will be energy that is owned by SERVCO -- by Genco, I'm sorry. Sorry, I misspoke myself. So it would be Genco generation who will own the energy that is being shifted to Hydro-Quebec and presumably Genco will have the agreement with Hydro-Quebec with what is the banking arrangement and under what conditions the energy is returned to Ontario. My question is: Does this type of scheme have any benefit to any Ontario market participant other than Genco? A. Well, as an integrated company the benefit of [Questioning] 311 Participants the scheme is flowing back to the ratepayer of Ontario. Banking allows a lower energy cost basically to the negative low. The decision was basically made under the current regime. MR. BARRIE: A. And to answer your question, yes, Genco are the beneficiaries of this particular scheme. Q. Okay. And the next question, I guess, is that if the large tie between Ontario and Quebec goes ahead, then that will also provide capability to move energy from the Ontario system into the Quebec system and will this program still be useful if that large tie goes ahead? A. Now, which program were you referring to again? Q. The large interconnection between Quebec and Ontario. I believe, a megawatt figure of 1,000 megawatts or thereabouts was mentioned this morning? A. 1250 megawatts. Q. 1250 megawatts. A. Yes. MR. CHOW: A. When the tie, according to current schedule, is not due to be in service until the end of 2001, this particular work at St. Lawrence, essentially based on the financial consideration and the current contract would have basically paid for itself by that time. Now, it would be still -- facility would still be there of use, but obviously it's criticality would diminish with the insertion of the HBDC tie. [Questioning] 312 Participants Q. Okay. And to continue on, there were some questions this morning about the Queenston interface constraining generation at Niagara and the New York imports. And Genco or Ontario Hydro has had a plan for many years to increase capability at the Beck generating station site and I'm wondering if this plan is contingent on that increase in generation going ahead at Niagara. A. The plan is not contingent on that, currently we have limitation on that interface already. The phase shifter will help somewhat. For the full use of that import capability from the tie you would have to do that second stage of the work in the Niagara. Now, obviously, any additional generation would add to the need for increased transmission capability in that area, but even if we don't, we foresee the need to reinforce the transmission in the Niagara for the purpose of the supply of load to the Ontario market. Q. It could be a difficult allocation problem coming up if Genco proposes to build that generation as to whether or not under the new philosophy of charging beneficiaries for the transmission connections that they incur, or made on their behalf, there could be a difficult question arising as to whether some of that cost should be allocated to Genco. I don't know whether you can comment on that? I see Dave nodding his head and maybe he wants to comment. MR. BARRIE: A. I'm just agreeing with the difficulty, Ken. [Questioning] 313 Participants When a particular reinforcement has numerous beneficiaries, then I think the answer is fairly obvious. When it becomes one or two beneficiaries, then I think you have the issue that you're speaking to. In terms of the Queenston capital project, though, Bob, have you got the timing for that project? MR. CHOW: A. The Queenston project basically schedules the last of the three project we have identified for improving the interconnection capability. The in-service date for that is scheduled for somewhere in the year 2003. Q. I think that raises the issue more clearly in that it's more likely to be dealt with under the new rules than, for instance, the St. Lawrence scheme which is largely under way and may be completed before the market opens and we get into a fully competitive situation? MR. BARRIE: A. All I point out, Ken, is it has very little impact on this particular rate order application. There is $1-million in the Year 2000, but I agree with your observation. Q. I believe that you mentioned, and again moving onto another area which is the network asset management/network asset services relationship and now you've mentioned that you've had this relationship or this structure in place for about, I think you mentioned three years? A. No, no, no. Much less than that. Well, it was -- I think it was the end of '97, wasn't it? [Questioning] 314 Participants MR. D'ARCEY: A. We have been involved in the relationship in through '97 and through '98. On the distribution side of it, we're a little more advanced. We had done a lot of the associated process redesign work and had formulated the first draft of service level agreements by the end of 1997. So we were more advanced on that side and we have been in through 1998 developing those and enhancing the distribution ones through '98. Q. Okay. One of the other things you mentioned and you mentioned it this morning again and I believe it was mentioned that last week, but when you set up this structure, you had looked at a number of other jurisdictions that had used a similar structure and you mentioned the United Kingdom perhaps having since abandoned it, Australia, New Zealand, and some jurisdictions in the U.S.A., and my question is: In these jurisdictions that have decided to continue with this scheme, are the network asset managers in those jurisdictions restricted to only placing their business with the network services organization or do they have freedom to place the business where they see it can be done best? A. Dependent upon the jurisdiction, you'll see variations of that. I think if you look at the New Zealand model, they have three service providers for the system. Other locations will have variations of that where a majority of it may be provided by an in-house and some of it external. So the model is somewhat flexible [Questioning] 315 Participants depending on what the local conditions are. Q. When you're preparing -- some network asset management is considering whether or not to carry out a capital plan, then it needs cost estimates to assess the alternatives at an early stage in the process, and later it will need detailed estimates of the cost of the actual proposed plan before approval of the work can be obtained. Who provides these cost estimates? MR. BARRIE: A. We would typically go to the services provider to provide, as you said, Ken, two sets of cost estimates. We have study estimates which help us decide what is the best alternative to proceed with, and then we have release quality estimates, which actually we require to get approval from the approving authority. And in both cases we would go to service provider to provide them. Q. Okay. And when it comes to actually releasing a capital plan to -- and releasing the work that has to be done under that, has network asset management ever released a plan to be conducted by somebody other than network services? MR. D'ARCEY: A. Yes. That has and does occur. Obviously, we are currently working within provisions of collective agreements and purchase service agreements that bind us with our unions, but our examples where we do not have the expertise in-house then that work then is done by a third party external firm. Q. But you have not found a case yet where you [Questioning] 316 Participants have the expertise in-house and the expertise or the services provided outside of the organization can be done at a lower cost or in a better manner? MR. DAVIES: A. I could give a couple of examples, Ken. Oil circuit breaker refurbishment program, the majority of that work is contracted external service providers. Air blast breaker refurbishment program, the majority of that work is contracted to external service providers. Q. Thank you. And you have mentioned the purchase services agreement and I believe that that is the agreement you have with the Power Workers' Union and the Society that represents the professional staff regarding out-sourcing of activities. And last week Ron Stewart said that the process has been improved. And I'm wondering if you can give us some indication of the steps that you have to go through if you want to implement that agreement and place business outside of the services organization? A. I can give some examples. One of the improvements has been that where there's a disagreement between ourselves and the Union, PWU, regarding the best decision for the company, there is now a mediator/arbitrator approach where we have an arbitrator that makes the final ruling which we didn't have that type of process in the past. Q. And how would you get to that? I mean, I presume that if the manager of a particular unit says I [Questioning] 317 Participants want to out-source this work and the union representative says I don't agree, I presume that you don't go to the mediator/arbitrator the next day and have a decision by Friday. How long does this process take, what steps do you have to go through to get to that point? A. The most recently signed collective agreement does provide for an expedited process that does actually produce a relatively fast result. It doesn't drag on for months and months. There is a very clear time line where the two parties exchange information, and if they agree to disagree, then it moves on to a mediator/arbitrator within a defined time frame and then the mediator/ arbitrator rules within that defined time frame. Q. Okay. And? MR. HARDY: Ken, I wonder if I can get some idea of how long you're going to be in terms of how many questions? MR. SNELSON: Okay. I have one other line of questions after this so you can either take the next question and break or listen to me for another 10 or 15 minutes. MR. HARDY: Why don't we take your -- why don't you sum up this line-- MR. SNELSON: Okay. MR. HARDY: --and then I'll open it up for other questions and then we'll come back-- MR. SNELSON: okay. MR. HARDY: --to you, okay? [Questioning] 318 Participants MR. SNELSON: Q. And I just really wanted you to comment on the way in which this kind of relationship with the Union is constraining you or not constraining you in your ability to find the best places to do this work? I mean, there can be all sorts of independent organizations who can do the sorts of services very often that you're looking for from the services company. MR. DAVIES: A. I think the most recent collective agreement put in place, the hiring hold concept for the PWU, which is a similar concept to the EPSCA trades have always have had, and just to put clarification to that, there is a jurisdiction boundary between PWU -- PWU work, I'll call it that, although work that the PWU would normally do and construction trades work. So there are boundaries between those two. The EPSCA trades, the construction trades, have had a hiring hold concept for many, many years which is essence means that gives the employer a lot of flexibility in terms of hiring for peaks and laying off for valleys. The most recent PWU collective agreement introduced a hiring hold concept which allows the employer to hire for peak workload within the PWU area and layoff when that work goes into a valley. So that is an example of where we have flexibility. We did not have that flexibility prior to the last collective agreement. Okay, thank you. I'll leave this at this time for the time being. MR. HARDY: We'll get back to you sometime soon. [Questioning] 319 Participants I just want to be sensitive to others that -- okay. Go ahead, please. MR. POCH (Green Energy Coalition): Yes, I just have a short follow-up on questions that I understand Jack Gibbons asked earlier. Q. I want to just ask about the Michigan intertie and I gather that you've already indicated that it's your understanding no other approvals -- environmental approvals are required for that intertie, correct? MR. BARRIE: A. At this point in time, yes. Q. All right. So I take it that there will be some impact on emissions and air quality and so on as a result of the energy interchanges that are going to occur and it's not a simple question as to what that would be, what the result will be. A. That is correct, it's not a simple question. Q. All right. And is it clear -- I take it it's your position that this isn't the hearing for us to examine that complex question? A. Well, that's the position I've stated. I believe I'm the transmission provider and the actual use of it and the differences that will make to emissions and everything else is really not my concern. Q. All right. Okay. But you'd agree with me, this is a situation where you're providing transmission not based on a market-driven call for it? A. No, quite the contrary. The market design [Questioning] 320 Participants committee had as part of an essential plank in the market power mitigation that we improve the ability to import and export, so-- Q. I understand, but -- A. --it's very much market-driven. Q. Well, there isn't some supply and demand happening out there that is driving up the price that's causing you to say, here's an opportunity. You haven't done that analysis? A. No, we haven't. Q. No. So this is being inspired by some public policy in issue? A. Yeah. It's a market design recommendation endorsed by the Ontario Cabinet. Q. All right. And has the Cabinet used some regulation to instruct you to go ahead and do this? A. There was -- we simply received a memo from the Minister indicating approval of the market mitigation measures. Q. All right. I'm just wondering what the mechanism here for -- that you're relying on here. It sounds like we're in a situation where the transmission company, the remaining regulated monopoly is going out building -- making capital investment that's going to be charged to rates and it is premising the need on some instruction. I'm just wondering - maybe your counsel can help you here - is there some -- are you relying on some statutory obligation or requirement for you to follow that [Questioning] 321 Participants direction or is it still an open question for this board? MRS. FORMUSA: I guess, David, it's -- David Barrie has explained the situation correctly in terms of what we've received in terms of instruction. Whether as part of the market -- the resolution of the whole market power mitigation scheme there is going to be a formal directive or not, I don't know. I understand your question, but I think as far as we're concerned, we have the memo from the Minister and we're relying on that in putting forward the capital plans. Obviously if further approvals are required, leave to construct and whatnot, there may be other instruments or directives in place by then, but right now this is what we have. MR. POCH: All right. Thank you. I think that's as far as I can go. MR. HARDY: Other questions? Go ahead. MR. BACON: Just a quick question, Bruce Bacon for OCAP. Q. I'm referring to page 82, table 7.6. Basically it summarizes your work program, capital program. My question relates to - and it may have related to my colleague here, his previous question - but you're showing for 1999 a total capital of 346-million, in 2000, 328-million and my question relates to risk. This is a plan -- this is what you plan on doing. My understanding from the application is that these are the capital [Questioning] 322 Participants programs which are included in rate base which impact revenue requirement which is what you're going forward for approval for the revenue requirement. My question relates to, what happens if these capital programs are higher; who bears the risk, the additional cost if the capital programs are actually higher? For example, you got 346 for 1999 and maybe it's 375 when you actually get it in place. Who bears that additional cost? MR. BARRIE: A. I believe this question of variations about these numbers was raised in Panel 1 and was -- which was -- I don't know that I've got anything more to add than the discussion that happened at that time. MS. FRANK: A. I think it depends a bit on the reason for the incremental cost. If we had, you know, and it's one of those please don't let it happen, another ice storm or some major event that resulted in a major restoration being required to the capital, I think our Panel 4, I believe it is, will talk a bit about a performance-based mechanism that would see us treating that as one of those exogenous events that we'd expect to get funded, you know, if it is a major out-there event. On the other hand, if we chose to spend more capital because our board decided that -- the Ontario Hydro services company board decided they wanted to make some productivity improvement and spend some capital money and get savings in the future, I don't expect we'd come [Questioning] 323 Participants back and ask for that extra money from the ... Q. So you're saying that would be the -- that the shareholder would bear the risk for that? A. For that type of one, yes, but once it were driven because of circumstances of, you know, in the environment in which we operate which we couldn't foresee at this point in time, I would think we would bring back to the OEB and ask them about those. Q. Actually, it could come back to the OEB for another review before it actually gets into rate base; is that what you're saying? A. Yes. MR. BAKER: Okay, thank you. MR. HARDY: Other questions? If not, we have some time before I intend to break. So Ken, why don't we come back to you then and finish off your next line? MR. SNELSON: These questions really started from page 80 of the main submission. Q. And at line 17, you describe a process for investment planning where all investment decisions for the coming year are considered at the same time forcing all investment proposals to compete against each other for funds. I don't know whether I'm misunderstanding the process, but it sounds to me as though this is sort of something like a sort of senior management set target level of capital spending and then selecting the most [Questioning] 324 Participants beneficial projects within that overall capital limit. And when I discussed with the Policy Panel last week the total level of capital spending and whether or not it was affordable as a whole, I didn't get a strong feeling that affordability had been given much weight and I'm wondering if you could describe in more detail how this competitive process works and how the overall level of spending which is to be allowed is set. MR. BARRIE: A. Well, I can speak specifically about the transmission business, not the whole OHSC business. There is not a cap given to us as such; however, like any business, we have to take affordability into consideration. This particular paragraph references a change in our process for deciding what to go ahead with. In the past, many projects would be identified over the course of a year and may or may not be implemented. As a result, it may well be that because of timing, the most urgent projects were not, in fact, carried out. That is if a project was identified at the beginning of the year and was halfway implemented, it would continue on to completion. It would be very unlikely that something would come along and bump it in the middle of the year. What we've tried to do and we haven't completely succeeded in this yet but we're well along the road toward doing it is at the beginning of the year to have a better handle on the total package facing us for development sustenance and operating capital, so that at the beginning [Questioning] 325 Participants of the year one can make those priority decisions on more of a level playing field when everything has been assessed at once and that is what we have strived to do this year. So for instance and I think probably in the sustainment area it's been the biggest effort, I've asked Tim to develop what the requirement is for sustaining capital for the whole year rather than spread it out across the whole year phasing it out as he would normally have done. So, in fact, that's what he has done. So at the beginning of the year, we have that knowledge of what's ahead of us in all three fields and we make the necessary tradeoffs at that point, as I said, not against a specific cap but against some judgment of what we think is reasonably affordable. And at that point, I would then be going to the senior management committee - well, now it would be the OHSC board but, of course, the board has only just been formed - to get approval for that overall program, so I will have done internal priorities before I go to the board across the whole program. Now, it may be that I don't get all the money I need at that point, in which case it has to be revisited, but I must say at this point, we have done our own assessment and what we believe to be the priorities in all three phases has been approved at this stage, at least went into this particular program. Tim, do you want to add anything on the sustainment ...? MR. DAVIES: A. Ken, you made a comment before [Questioning] 326 Participants about, well, surely in the past, you knew of the condition of the assets were. You were measuring condition of assets. And yes, that was true but in a very spotty fashion. In the last year, we've put a large amount of effort to actually assessing the actual condition of the assets out there and we have a much better handle on the condition of assets far better than we've ever had in the past but we've still got a way to go. I'll give you an example: A typical experience with conductor is that on average it will last between 50 and 60 years and that we find conductors starting to fail because of corrosion after 50 years. Now, right now we have on the system close to 9500 -- 9,500 kilometres of conductor that is greater than 50 years old. We know the condition of approximately 5,000 kilometres of that conductor. By the end of this year, we will know the condition of the remaining 4,500 kilometres of conductor that is greater than 50 years old. And when I say "condition", that means laboratory testing. It isn't a case of just somebody going out there and just looking at it and say, yeah, it looks good enough. It is actually laboratory testing. Based on our knowledge of the conductor that has been laboratory tested, that 5,000 kilometres, our program has been put together for 1999 and Year 2000. So there's a lot more knowledge on the condition of the conductor than we had in the past, but we've got a way to go to have 100 per cent knowledge. [Questioning] 327 Participants Q. You know, the question really was -- that's interesting and that does help, but the basic question was really more about the overall affordability of the capital plans and -- I come back to sort of the -- one of your appendices shows the cost of power expected in 1999 and the cost of power expected in 2000 - I've not got the reference right here - and all the components that go into the final cost that customers pay. And it seems to me that the -- at least in the 1999 and 2000 with the ability of Genco to control the market price of electricity and with the charges that are going to be made for stranded assets and so on, that the cost of power to customers is not likely to come down significantly in 1999 or 2000 as a result of all these reorganizations. And I'm wondering, why would SERVCO expect the Ontario Energy Board to take a different view as to what is affordable from a customer's perspective than the Ontario Hydro board took last year in the 1998 business planning process? MR. BARRIE: A. Ken, I don't want to reiterate what I've already said, so ... I'm simply saying that this is my judgment of what is required to be spent on capital to prevent deterioration of a system beyond what is acceptable to the customer. If this capital program is not approved, then I believe it will adversely affect system reliability. MR. SNELSON: Okay, those are all my questions. MR. HARDY: Thanks, Ken. [Questioning] 328 Participants Are there other questions? MS. FRANK: A. I want to add something in terms of the last -- the board from a year ago and the consideration and judgment that they might have had in coming up with a capital program. I believe there's different information today than there was a year ago that the Ontario Hydro board would have made. There's things like, should we have any interconnection program here or should we not? That's a new piece of information that the board wouldn't have had a year ago. A lot of the asset condition work that was being done was really at the time period that the board was making decisions and we hadn't had enough information to fully put it into our programs. So I believe there is a change in circumstance because what the board -- the Ontario Hydro board approved for a capital program across Ontario Hydro a year ago and what we've got in terms of an understanding of the condition of the assets, the need for the marketplace in terms of a marketplace redesign, the demerger capital costs that we've got in the transmission support area. They're all new pieces of information, so I don't think you can just take an absolute level that the Ontario Hydro board thought was appropriate in 1998 and say, why isn't that appropriate in 2000? This information has gone to the management of the old Ontario Hydro as we today are still an integrated company and they thought it was very credible information for us as a program. Dave has defended this program to [Questioning] 329 Participants the management committee of Ontario Hydro and many times extensive review and they thought it was appropriate for us to bring forward for this submission. MR. HARDY: I don't know if you have a follow-up or not. MR. SNELSON: No. MR. HARDY: Fine. It's a good time to break. Why don't we break for an hour or an hour and a couple of minutes? It would bring us back here at about one o'clock then. Okay, thank you. ---Luncheon recess at 11:58 a.m. ---On resuming at 1:05 p.m. MR. HARDY: We'll get going. I understand that our panel has a response to one of the earlier questions this morning. I believe it was specific to the forecast magnitude and quantification of predicted savings related to the network asset management model for the next two years in terms of millions of dollars in savings and staff numbers. Is that the question you wanted to help us with? MS. FRANK: Yes, it is. Thank you, Dave. You had asked us if we could quantify some of the savings that we talked about in general terms and we talked about the savings coming from the network services area in terms of some of their efficiencies, fewer locations that they were going to operate out of and that type of thing. Then also it may be some savings from the asset [Questioning] 330 Board Staff/Consultants manager and also from the functions and services groups at the OHSC level. And if you add all the savings together, total OM&A and capital savings, so all dollars spent, it would be in the $15- to 20-million in 1999 is the kind of savings that we've got in the numbers that have been filed and then a further $35- to 40-million in 2000. That's the dollar magnitude of the savings that we're talking about. In terms of the staff question from Panel 1, there was an agreement that we would provide transitional-type staff information so I believe you'll get that from that other filing. MS. SIMMONS: Can I just ask you that 20- to 30-million that you anticipate in the Year 2000 savings, is that something that I would refer to as a continuous level of savings; it's annual savings you could save over some long-term period as a result of implementing this and achieving savings from fleet management and work re-design and re-management? MS. FRANK: Yes, first of all. And that's why I described the 2000 as additional or further savings because the amount that we've got in 1999 we've now embedded into the program. If you close down a garage, the garage is gone and that saving is maintained indefinitely. MR. HARDY: Thank you very much for helping us with that. I wonder if we can then begin the afternoon's [Questioning] 331 Board Staff/Consultants questioning with Board Staff and Board consultants. Neil, if you could also introduce yourself? MR. McKAY (Board Staff): Neil McKay, I'm with Board Staff. Just a couple of things arising out of this morning's discussion. Q. I was wondering if you could just clarify, the Asset Condition Study itself, exactly when was that initiated; is there a date that you have? MR. BARRIE: A. Tim, would you like to speak to that? MR. DAVIES: A. Yes, this was study that was done I believe in the fall of 1997. It was done by Ontario Hydro with an external consultant in a managerial and overview role. Now, that is separate to the very detailed Asset Assessment activities that are ongoing as we speak and have been ongoing in 1998. Q. Who was it in Ontario Hydro that decided to initiate the actual study? A. I believe it came out the Nuclear Asset Assessment Study that was done on our nuclear plants. And when the Board received that, the direction was to do a similar detailed assessment of all other assets in the corporation. So it came from senior management level. Q. This was definitely like a one-time off study? A. Yes. Q. Can you just help me with the time period [Questioning] 332 Board Staff/Consultants that it covers? It kicks in in '99 and you've got sustainment capital associated with it in the Year 2000 as well. Does it carry on beyond that? A. The expectation is that our expenditures in sustainment capital will be increasing beyond Year 2000. So the asset sustainment capital ramp-up is not a two-year ramp-up. Q. And just one question arising out of some questions that Jack Gibbons asked this morning, will you require additional export licences from the National Energy Board when those facilities are in place for the interconnects? MR. CHOW: A. Are you referring to the U.S. interconnections? Q. Yes. A. No, I don't believe so. Q. Thank you very much. MS. BULKLEY (Reed): I would like to ask a couple of questions going back to the capital planning. Q. Before the break we discussed a little bit about how the network asset management model goes about its planning. I was wondering if you could just give me a little bit more information about the process that you used historically to plan for transmission investment, if you can provide something more than what you discussed earlier which was to say that you planned throughout the year? Can you provide me better detail on that? [Questioning] 333 Board Staff/Consultants MR. BARRIE: A. This was prior to the introduction of the Asset Management Model? Q. That's correct. A. If one goes back -- let's go back ten years to start with. We had completely separate divisions within Ontario Hydro, one doing system planning, another group in the Regions Branch doing what's roughly equivalent to what's now in sustainment. So we had completely disparate groups planning in Ontario Hydro, what is now all done within my business. In 1993, those very different groups were consolidated into the grid business unit and at that time although there was some coming together, the kinds of activity you've just described was still developed separately by two groups, one in Grid District Operations who was doing mainly the maintenance-type planning and the division that I headed up at that time, Grid System Strategies and Plans, which was doing all the development work and that kind of thing. So I think the big difference prior to '98 was that they tended to be separate activities. There was a lack of integration. Tim was more deeply involved in that at that time. Would you like to add anything, Tim? MR. DAVIES: A. On what we called District Operations which was really the successor of the Regions Branch, we had a decentralized leadership. We had ten districts that were geographical entities across the [Questioning] 334 Board Staff/Consultants province and the majority of maintenance planning, both O&M and capital, was done in a decentralized fashion. So clearly the leadership of each of those ten districts had a very personal interest in the investment and facilities in their particular location. There was some integration in head office but it was of a limited amount and I think it would be fair to say that there wasn't a lot of long-term planning in the decentralized units, the focus being keep the lights on today and tomorrow, not what is the situation in three or five years' time. MS. SIMMONS: So what is your planning horizon now that you're aiming for when you're doing your planning? If it's not three to five years, is it ten to twenty; how has that changed? A. Perhaps I could use an example. We had a circuit I believe in Oakville, running through Oakville, Bob, it was at end of life, conductor was about to fail. The old style would have been that the Grid District Operations would have looked at rebuilding that circuit. In the new model the Development people and the Sustainment people work closely together and determine what's the optimum solution to that particular problem. In that particular project, the solution was not to rebuild the circuit. It was, in essence, to build a new transformer station so that the existing transformer station that was fed by those lines - it's been decommissioned - and the customer load is fed out of that [Questioning] 335 Board Staff/Consultants new transformer station and I believe that was perceived as the most benefit to the Ontario Hydro to the customers and to the stakeholders, that particular solution. So a much more integrated approach between sustainment activities and development activities. Q. Okay. Can you give me a sense of what impact the introduction of an open market is going to have on capital planning processes? MR. BARRIE: A. Well, I think the single biggest thing and this has been reflected all around the world by every transmission company that faces open access after being part of a vertically integrated company is the degree of uncertainty. Planning always has uncertainty surrounding it but the degree of uncertainty increases by an order of magnitude. We now no longer know with any certainty at all where the new generation is going to be. So I see particularly in the Development area a change towards being quickly responsive to the needs of the market as distinct from putting forward a ten-year plan for the development of the system. It would be ludicrous to even suggest we could even do that in the development area. So my emphasis to my Development group is that we must be responsive. We must be able to respond far more quickly than perhaps we were able do in the past to changes in the way the market is likely to evolve. I know what happens in places like National Grid Company, for instance, if a new generator is considering [Questioning] 336 Board Staff/Consultants connecting at some place in the system and makes application to National Grid, they require an answer within 90 days as to the feasibility of connecting. That doesn't say necessarily the answer is yes, mind, but they do get an answer. So things happen a lot more quickly in this environment than perhaps in the old environment where you had a ten-year plan that you basically tried to stick to because you thought you knew exactly where all the generation was going to go. I think that's the single biggest difference. On the sustaining side, it's largely the same. We need to maintain the existing facilities to satisfy our reliability requirements and our commitments to our interconnected neighbours. So that really doesn't change. That would be the single biggest change. Bob or Tim, do you want to add anything? MR. CHOW: A. Obviously, on the development side, as Dave alluded to, there's a lot more uncertainty. There's also another dimension is that there's a part of the business that today is a monopoly which is the connection site, is going to be compared in the future. So development in that area is going to have go through a transformation. Again, it depends on the way the market is unfolding and to what degree does the connection distance still belong in a way it's currently used today to the transmission company. Q. Can you determine or can you give me some information about whether the IMO will impact your [Questioning] 337 Board Staff/Consultants planning process, and if so, how? MR. BARRIE: A. Of course this is still under discussion right now as we speak. I can tell you my expectations and you can take that for what it's worth. The IMO will be involved particularly in the identification of need. They are probably in the best position to know, for instance, whether there is likely to be bottlenecks on the system, whether there will be constraints on the system that would prevent the open market functioning without any transmission constraints, so I would expect them to play a major role in the identification of need. So then when the need's been identified, I would expect ourselves and possibly other transmission providers to be putting forward solutions to constraints. When that's done, I imagine they will be tabled, if they have major capital, in particular, it will be tabled to the OEB, in fact, and the IMO, I would say, providing a technical assistance to the OEB in the assessment of alternatives. So I would say that they would have a dual role: Identification of need and assistance to the OEB in the assessment of technical alternatives. MS. SIMMONS: Q. Can I just ask for some clarification. You stated that the IMO would be in the best position to know if and where there are bottlenecks on the system. Why wouldn't you know as part of your transmission operations management centre, wouldn't you know or are you saying at a higher level they will know [Questioning] 338 Board Staff/Consultants from how the markets had to redesign, will you both know or will they know? I'm a bit unclear on that. A. I think they are in the best position. We will certainly have indications ourselves, of course, because we will know from our own facilities where things are being restricted. Q. But you're saying they'll know how things are being re-dispatched to meet those constraints-- A. Yes. Q. --and you won't? A. They will and they have the best handle on what's going on in the interconnections as well. They are the primary interface on a commercial basis with transactions with Michigan, New York and Quebec. They will have the best knowledge and we'll have the best knowledge of what is likely to be developing in that horizon. We have some indication, certainly, but they are the ones who are actually operating the market. When a limitation occurs on the integrated system, there is a technique used amongst all the interconnected utilities called transmission limitation relief which the IMO, as the security coordinator for this part of world in Ontario, actually implements, so they are actually the people who relieve constraints on the transmission when they actually occur. That's why I said I felt they were in the best position. We know when it's occurring as well, of course, but I think they have better information than we will have. [Questioning] 339 Board Staff/Consultants Q. The market demand, what's going on and things like that? A. Exactly. Really the market is not really our concern. The actual flows on our equipment is our concern, but who is selling to who is really not our concern. Q. Okay. I wanted to also ask you, you indicated you -- and maybe I misinterpreted that you haven't or do not have in your transmission development plan an assessment of your own system where you see the need over the next 10, 20 years for reinforcements or redesign to deal with some forecasted projection of market demand; is that correct? A. No, I didn't want -- I don't want to suggest we don't have any plan. We are not putting forward long term plans the way we might have done in the past. We certainly don't know what's happening 10 years from now. We will be looking forward to the best we can, to the best of our ability, but we typically will now be perhaps looking at a five-year horizon, and even within that five-year horizon, we are acknowledging tremendous uncertainty beyond say a two-year horizon. This is particularly in the development area so perhaps Bob should speak to it. MR. CHOW: A. Well, as in any business, you want it to expand further, because for example submit a program, obviously you want to look at scenarios. We look at work potentials, traffic on a system on a network, say, [Questioning] 340 Board Staff/Consultants low growth in terms of the connection end of the business. I think we do that as part of our work. How far do we go? It depends on the situation. Your information is good enough to extend beyond a certain horizon, then you probably want to use it and take a look at what option you have. Dave mentioned you have to be very responsive to the market's need, so one thing we are going to move forward in the future is look at what we have to do, for example, to respond to market need and go on to an assessment process required in a certain area, let's say, or the lead time of equipment if you have to order very quickly. Those things we'll be looking at on a continuous basis, but that's just a part of the work you do to put into the element of the future program. Q. Okay. I do understand that the Market Design Committee is looking at things like locational-based marginal pricing, but that's something that will be implemented in the future. This is a very important transition time and there's likely to be interest in generation siting especially as a result of the expectation of greater export capability from out of Ontario. Given that, do you have an indication right now based on your, you know, development studies that have been done today where it would be beneficial or not beneficial for generation to be sited in the province? A. We have on a general basis understand where [Questioning] 341 Board Staff/Consultants are the goods sites and where are the bad sites, but right now we're waiting like everybody else for the market to start, I think. MR. BARRIE: A. It's a general observation. Generation is normally advantageous to a transmission network if it is sited in a load-rich area. I mean, it's stating the obvious, but basically that's universally true. If you site generation in a place that's currently being fed from elsewhere in the province, you will tend to ease back on the flows. So it you were to put a generator in downtown Toronto here, and you could get approval for that, from a transmission perspective it would be a good thing. Q. But right now in your pricing regime, there's no sort of signals to the market between that time before L&P is being implemented and you don't have plans to sort of give that market information up? A. Not in what is being suggested now. In previous work we were doing, we did look at how we would divide up the system in terms of zones, which is a rough and ready locational marginal pricing if you will. It doesn't do every node, but it just groups a whole bunch of nodes where it will be similarly priced, and we ended up with about ten areas, but this was just where we were thinking initially of how we might price transmission in various areas. There are some things against that, of course, the whole notion of charging people differently in [Questioning] 342 Board Staff/Consultants different geographical areas of this province has certain political overtones that might not be appreciated either, but we did look at that from a pure transmission perspective of where it would be advantageous and therefore you want to encourage people to site generation and where it is not. We have done that work and we have got a dozen sectors which indicate the differences. Q. Okay. Because you made reference to the National Grid Company and how quickly they reacted, and as you are aware they do have specific-- A. Right. Q. --generation rates by area so to the extent, you know, generation comes in, they already know that it's going to be cost more in a certain area and cost less in another and I'm just trying to understand the corollary here in Ontario and it sounds like you know that information, it's just not public? A. We know the information, we know the phenomena. It is not part of our rate application. MS. BULKLEY: Q. Earlier today you gave two examples of services that were performed by outside service providers and I just wanted to get a sense of what the policy is going forward on that? When a determination is made that transmission investment needs to be made, will that be taken to the competitive market and evaluate the costs of having someone outside do it as compared to network services before the work is performed by internal resources? [Questioning] 343 Board Staff/Consultants MR. DAVIES: A. I think the long-term intention is precisely that, to move to a fully contestable service provider regime in the immediate future, we are basing it on our judgment in asset management on where the service provider is uncompetitive versus the external service provider versus immediately going to the open market for bids to invite public bids on all work. Q. How is that judgment being made? A. Basically at the experience of the people in asset management based on their knowledge of what it should be costing to do this work and what perhaps the other service providers outside Ontario Hydro can provide. Q. So then you actually are going out and getting -- A. On selected projects we are inviting proposals, yes. Q. Okay. MS. SIMMONS (Reed): Q. You're doing a lot of different programs in this rate application or you've described a number of different programs that you're doing, would you characterize any of those programs as getting your network services business prepared to compete for projects in the future? MR. D'ARCEY: A. Could you repeat the question one more time? Q. Well, I am trying to understand whether there are any -- there are any specific programs or activities that you're doing now in anticipation of knowing that [Questioning] 344 Board Staff/Consultants there's potentially future projects and activities may be contestable, so are you doing things now trying to eke out efficiencies so that network services will be the, you know, the least cost provider going forward and you won't have to go to market? I'm not sure if there is anything, I'm just trying to understand whether there's $10-million in here to, you know, build this great dispatching centre so that your people can efficiently go out in the projects. And you know, that's just one example. A. We have, over the past couple of years, been looking at improving upon our efficiencies. We've done some process redesign work on key processes within the business. We've also invested recently in work management systems which we've just recently put into service in the past couple of months. We are also, as I mentioned a couple -- earlier in the day, we are looking at facility rationalization, we've have amalgamated our current organization and it is set up to leverage the resources within the province to create more of a mobile work force. We have negotiated with our unions a hiring hall with the PWU which gives us increased flexibility of the work force. So yes, we have done several things and have several initiatives under way which will reduce the cost to deliver the service and make us more efficient in the delivery of that. Q. Okay. I think we would like to get into some details now on some specific programs. I don't know [Questioning] 345 Participants whether there's any more questions from the audience before we get into detailed program? MR. HARDY: Maybe I will take this as a time just for me to poll. Why don't I just see who is. Are there other questions that are appropriate at this point either from what the panel has provided or some of the questions arising from the Board Staff and Consultants? I'll take them now and then we can get back to Board Staff. Richard. MR. STEPHENSON: I have a couple of areas. Q. Looking forward following up on the issue about the congestion pricing for transmission and the postage stamp rates in the future potentially for transmission, perhaps. In terms of the capital plan you're proposing today, whether in terms of projects or in terms of your operations centre and so forth, is there anything you're doing there that either facilitates or hinders or just is neutral with respect to any future implementation of any nodal pricing or congestion pricing system? MR. BARRIE: A. I don't see any linkage between any of our programs and the implementation of nodal pricing. MR. DAVIES: A. Yes, I agree. I think currently, and I don't anticipate changing in the future, the end of life criteria of particular assets is not being differentiated across the [Questioning] 346 Participants province; in other words in insulators at end of life, whether it downtown Toronto or Kapuskasing. Q. On another area I heard this morning, one of the efficiencies that -- and you've brought to the plan before the Board today something, I think you referred to it as a reliability-based maintenance. MR. BARRIE: A. Reliability-centred maintenance. Q. Reliability-centred maintenance, thank you. Can you just describe for us how that -- where you're at in terms of introducing that as a concept and how that concept differs from what you either are presently doing or have done historically? MR. DAVIES: A. The RCM philosophy is applicable to the O&M program and-- Q. Okay. Well, we can come back to it -- A. --rather than -- so perhaps it would be appropriate to talk to it tomorrow because it's context for our O&M programs. Q. That's fine. Okay. The last I've got for you is on the performance measures. You listed them in the material you gave us this morning and it's also in the material. The question I had is: I know some of these have been tracked historically by the grid or some aspect of Hydro. Are any of these new? Are these new in terms of being measured or are they -- or do they vary in some way from what's been done historically? MR. BARRIE: A. Of the five listed, the first [Questioning] 347 Participants two are really splitting out the previous measure we used to have of what we called CDI, customer delivery interruption. We tried to amalgamate both the amount of energy not supplied plus the number of interruptions that actually occurred. It was something we invented ourselves and no one else did it. We were trying to come up with a single number and that historically is what we did. So what we've done now is to split that out into two separate indices, on supplied energy a number of actual interruptions, which brings us more in the line with what other utilities measure and so allows a more ready benchmarking. So those two, you could say, we were already measuring but just reporting in a different way. The other three are actually new. Q. Well, can I just help me on this? In your filing -- it's starting at, I guess, pages -- it's around 50 something, 51 and following. You do go through these one at a time and you talk about historical performance and what your target is and that's why I -- A. I'm sorry, when I said "new", of course these things were going on all the time; it's just we weren't being judged against them. So we do have historical performance on how we did against these things. It's just briefly they weren't specific measures that, for instance, I was being judged on. Q. I mean -- I guess -- let me just go back to this. Is this a matter of, these were measures that were, in fact, tracked but not reported in any systematic basis [Questioning] 348 Participants or is it that you had raw data that you didn't compile into these figures? A. Raw data. Raw data was available, but I didn't -- I had never seen that actual measure expressed as such until this year. MR. HARDY: Can I just clarify for the point of the record here, it's the new one that you're referring to of one-hour restoration, 24-hour restoration, transition system unavailability; were those the new ones? MR. BARRIE: Yes, that's correct. MR. HARDY: Thank you. MR. BARRIE: So we have the raw data and we were able to go back and track what they would have been had we been measuring them, but we weren't actually measuring them. MR. STEPHENSON: Q. Okay. That's exactly what I was looking at. And then -- I know that the first of the -- the first two are system measures for the entire bulk system. The latter three, are they -- those are delivery point measures or what -- where are they tracked from? MR. BARRIE: A. Well, they're all really based on delivery points. I mean, if the first two were unsupplied energy because of an interruption at a delivery point or it might be a number of delivery points for any one incident, but that's how we get our data, by looking at the interphase between the transmission network and whoever we're supplying at a bulk delivery point. So both [Questioning] 349 Participants interruptions and unsupplied energy are measured there. Equally well, 24- and one-hour restoration again are related to some transmission customer being off supply. It's actually the fifth one, the one that refers to -- what is it, system availability or ...? Q. Yes. A. Right. That's truly more of a system one if you wanted to classify it as a system. It's not related to one bulk supply point. It's looking overall at all of the circuits that you have and what your average availability of all of those circuits. Q. In terms of the restoration ones, those are not averaged figures I take it in the sense of -- those you literally track all of the outages at a particular delivery point and you measure how many of them were restored in one hour and how many of them were not restored in one hour and you're simply reporting about your ability to, in fact, restore in an hour or not; is that -- do I understand that measurement correctly? A. Yes. We take each event, was it restored within an hour or not, and then you take all of them and say what percentage were restored within an hour. MR. STEPHENSON: That's all. Thank you. MR. HARDY: All right. Are there other questions? Go ahead, please. MR. FISHER: My name is James Fisher. I'm appearing on behalf of AMPCO. Q. I'd like to ask some questions with respect [Questioning] 350 Participants to the assessment of assets that referred to in section 7 of the application. And there are many statements indicating that a particular percentage of an asset is 'X' number of it years old. For example, on page 86, it says 30 per cent of the insulators are 50 per cent -- or are 50 years old or greater and near the end of their life and those manufactured between 1965 and 1980 have premature lives. Similarly, on page 89, it says that 80 per cent of the relay protection system is greater than 26 years old. 26 per cent of this equipment is more than 45 years old. Would you tell the Board what sort of assessment was done in 1990 on transmission assets? MR. DAVIES: A. 1990? Q. Yes. A. I don't think there was a coordinated assessment on assets in 1990. I just wonder why you chose 1990. Q. Well, just to get a sense of, you know, what was happening for asset assessment ten years ago for example. A. Oh, I'm sorry, okay. I understand. It was a very ad hoc approach-- Q. Okay. A. --not particularly widespread .... Q. And what information did management look for in their decision-making with respect to the allocation of capital for the transmission system? A. In 1990-- [Questioning] 351 Participants Q. Yes. A. --or in 1999? I can't personally answer that because I was not involved in 1990. I can -- I think I'd refer back to a previous answer that basically said our organization structure in those days was a decentralized management approach, that different priorities for capital expenditures would be used in different parts of the province. MR. BARRIE: A. Was that your question or are you asking about how much was allocated to transmission as a whole? Q. No. I was just wondering generally how the decision-making was made. If there's no ongoing assessment, management wouldn't have any ongoing information as to the condition of the assets, so how do they make decisions? MR. DAVIES: A. I think it would be driven by a specific issue at that particular point in time rather than looking at all assets and saying, not only do we have a problem at this location, we have a similar problem at 15 other locations, so, therefore, we need a game plan for all 15 locations. Q. So that would be how management -- A. Perhaps I can give an example: I was one of those distributed managers by the way so I can't kind of pretend that I wasn't part of the problem. As a district manager, I distinctly recall cap and pin insulators. We had a lengthy outage to one particular MEA at one [Questioning] 352 Participants particular distributor caused by a failure of cap and pin insulators, so that general manager of the PUC was extremely upset. He bent my ear extensively and quite frankly, that was a priority for the following year, was to change all the cap and pin insulators in the station that fed that particular PUC. We were reacting to issues rather than looking right across the district and saying, we've got these cap and pin insulators in these 15 stations and we're going to put a game plan together to address all those 15 stations. Q. So management would not have had a sense then of the overall condition of the system -- A. I would say senior management did not have a sense, yes. Q. And have you any idea why there was no ongoing across-the-board assessment of condition of the assets? A. I think the -- I can only surmise, and I was not part of senior management then, but I can only surmise that they had other priorities, that there were other issues facing the corporation at that particular point in time and those priorities did not include transmission. Q. One of the things that, you know, this raised in my mind when I was reading this, where it says 30 per cent of the insulators are greater than 50 years old and near the end of their life, so does that does that mean that ten years ago, say in 1990 then, 30 per cent were greater than 40 years old? [Questioning] 353 Participants A. Yes. Q. Okay. And similarly, it said those manufactured between '65 and 1980 had premature lives, premature-ending lives. A. Right. Q. So in 1990, ten years ago, management would have known about that as well? A. Engineering would have known about it. Whether engineering was particularly effective in articulating that issue to senior management is a question I won't comment on. Q. Of course. Well, I guess that leads to the question, you know, why wasn't any of this work done in the past when it was known to be needed? A. Well, I think the response is, quite frankly, is that the current senior management will recognize the issue and have set up the asset management model to allow a group of people to focus on the assets rather than the issues of implementing work programs, so Dave Barrie and his staff are able to focus exclusively on the assets and Myles and his peers can focus exclusively on executing the decisions of the asset manager. MR. FISHER: That's all, thank you. MR. HARDY: Are there any other questions from participants? ---(No response) Can we return to Board Staff and Consultants then, please? [Questioning] 354 Board Staff/Consultants MS. SIMMONS (Reed): Q. I guess the easiest way for me to go through this is to start on page 84 where you begin to describe your transmission capital work programs and there's specific programs that we would just like some greater clarification on and I do recognize you provided some supplemental information and I'm going to try to refer to it and just specific questions on that, but just go through some of these questions with me, some of which you've answered generally but would be important for our understanding to go through them again and understand where decisions are being made because of the asset condition and why things are being done over a particular time frame. So if I start right now with the station's programs and the station's component program, if you could just, please, indicate to me whether this activity -- the level of activity that we see here appears to be at a higher level than that which has occurred historically and I know what's going on in 2000, but I really don't know what's going on before that. Do you see the level of activity in this program to be continuing at this pace for the next five years? MR. HARDY: Are you referring to Table 7.7? MR. SIMMONS: That is correct. MR. HARDY: Thank you. MS. SIMMONS: And I'm referring to item 1.1.1, station components. MR. HARDY: Thank you. [Questioning] 355 Board Staff/Consultants MR. DAVIES: A. I would expect it to run beyond the numbers shown. With some -- the regulatory environment and safety programs, I believe, will be pretty flat, but the other numbers I'm expecting to ramp up. MS. SIMMONS: Q. So you're referring to some of the other -- I was just focusing on station components and which some of which are -- MR. DAVIES: A. So that's Table 7.8 then -- or 7-8 rather than 7-7? Q. That's probably correct. A. Okay. Our circuit breaker program I would expect to be at relatively the same level in the future. Power equipment and those other programs, Pickering switch yards, I would not expect to be beyond 2000. That's a specific program over a two-year period. The power equipment program, I believe, ramps up more than shown. Control and metering ramps up beyond what is shown -- well, yes, it does ramp up beyond showing, sorry. Civil program is, I think, approximately flat, 5- to 7-million. Protection programs is around 9- to 10-million in the longer term. ACDC service supply, I believe, is typically 3- to 4-million in the longer-term and I said Pickering is a one-term issue at this point in time. Q. I know you've addressed it before, but a lot of times in your initial filing it indicates these programs are aimed at replacing or refurbishing components that have reached the end of their lives and a lot of it, you refer to, maybe it's not with respect to these [Questioning] 356 Board Staff/Consultants components that there's -- the quality of the asset is below what you would expect. Is the rate of repair replacement consistent with the manufacturer's standards and recommendations for these different components? A. Generally, we're getting more life out of our components than the manufacturer initially indicates. Q. Okay. Is your rate of repair and refurbishment consistent with other utilities? I mean, I know it's hard to compare based on your own system conditions and weather conditions that are experienced, but when you talk about benchmarking, do you benchmark performance of individual components against other utilities, the same performance with those manufacturers? A. At this time, no, we tend to benchmark on system performance so I can only comment on anecdotal information that we may gain through informal contacts with other utilities. Other utilities -- some of the other utilities I'm familiar with are replacing their assets quicker than we're replacing ours. I might add though that in some cases the conditions they're facing are different. I hate to keep harping on about overhead lines but Britain and Europe typically are replacing their conductors and towers quicker than we are but that may reflect higher atmospheric pollution in those particular parts of the world. Whereas Scandinavia, the lifespan of their towers [Questioning] 357 Board Staff/Consultants and conductors tends to be similar to what we're experiencing which again may reflect atmospheric pollution. But you also have to I think recognize that the age is also influenced by the original specification, the quality of the manufacturer at the time, as well as events after the equipment is placed in service. Q. Okay. On page 90 in this section where you're referring to station components, there's a statement there that says: 'Under such a scenario...' And I'm looking at line 22. '...it is expected that the networking customer connections would experience an increasing rate of failures and unplanned outages. Some of the failures may have safety implications for both public and field staff.' I think that's with respect to a couple of the programs. Have you quantified this or have you estimated it? It's a statement that appears repeatedly and I'm just wondering on what basis you've made the statement specifically here with respect to these station components? A. I can't table a detailed engineering study that specifically addresses that. If we don't spend $2-million on a particular program that CDI will change from X to Y. Q. Just based on your experience? [Questioning] 358 Board Staff/Consultants A. Yeah, okay, it's based on our experience but also an expectation that as the frequency of failure of the individual components, given the design of the particular system the components are in, eventually the probability of an outage of the system is much higher given the failure rates of components are increasing. It's a fact of statistical life. Q. Okay. I follow that. Help me understand and I'll ask this question probably again, it appears that these levels are higher than what is has been experienced previously. Why is it necessary to undertake this level of activity with respect to station components at the level you've planned for for the next year? Is there a longer life period by which you could make these replacements? Could you slow down this program and, if so -- or is this like the second best program? Have you already had a program with a lot more work and this is really what you think is reasonable? A. What this program is based on is actual condition of assets that we have measured or we have reviewed, investigated, inspected. There are a fair number of assets we have not inspected yet in a detailed way. So this program is based on our knowledge of the assets today and engineering standards of which we believe it's prudent and safe to keep an asset in place, asset in-service versus taking it out of service. So, for instance, we have a standard for insulators. A 115 kV insulator would have seven elements. [Questioning] 359 Board Staff/Consultants We have an engineering standard that basically says if you have -- in certain circumstances if three or more of those units of the seven unit string are defective, then you need to replace that immediately for public safety and employee safety issues. In other words it can fail at any time. If you have four or more of those elements still good out of a string of seven, then replacement can be deferred for six months. And if you've got five or more of the seven elements still in good shape, replacement of the two defective elements can be deferred indefinitely. Q. So are you saying that all of these projects need to be done for this coming year to meet your own safety and engineering standards? A. Not all of them have to meet safety standards. Some of them clearly have safety implications if they're not done for both the public and employees but others have an implication to reliability. Q. Okay. So there is a situation that I could envision where there could be a delay in implementing these programs or replacing or refurbishing these components at the rate you projected in here and the outcome under that scenario potentially could be higher rates of failure, increased outages or something? A. Well, I'll give you one example. We have in this program some money for oil containment. These are oil containment facilities around transformers. We have a little over 700 power transformers on the system and over [Questioning] 360 Board Staff/Consultants 1,400 transformers of all types. Of those 700 power transformers, more than 100 of them have absolutely no containment. So if we have a major spill such as the tank splitting because of an explosive failure in that transformer, then that oil will immediately flow onto the ground. Now, in some locations that is not a big issue because through having a service level agreement with a service provider on response time to get to that station, they can contain the oil before it gets off the site. But there are some locations we have serious concerns that notwithstanding the best efforts from the service provider, the oil would get off-site and into flowing water off-site and, therefore, we have in the program capital expenditures for oil containment in some of those facilities. What I'm trying to explain is it goes beyond reliability; it goes beyond public safety and employee safety. There are also some environmentally-driven programs as well. Another example may be fence replacements. Fence replacements don't necessarily impact reliability except if people get inside the fence and get into energized equipment. Chances are the equipment will trip and interrupt the customer but much more seriously that person may be killed. You may say, well, that's their fault but in many cases it's a situation with children. You could call it the innocents, that we're trying to keep the [Questioning] 361 Board Staff/Consultants innocents out of our station. Q. I'll come back to you on a few other things. We're going to talk about a few more programs. MS. BULKLEY (Reed): Q. If I could direct you to Table 710 on page 92, I was wondering if you could tell me whether or not the rates of replacement listed here for '99 and 2000 are similar to the historical rates for these stations? MR. DAVIES: A. I believe they're slightly expanded beyond the historical replacements. I don't have the number in front of me but I believe historically the number was a little less than 25 to 29. Q. Okay. I think that may just have been omitted in a subsequent filing, the averages. Is that a number that you could provide? A. We'll look at the practicality of providing it. Q. Okay. MR. HARDY: Sorry, just to get that information coming forward down. MS. BULKLEY: Right. This is in reference to table 710 Major Essen (phoen) Station Projects. I'm just looking for the five-year average number that was similar to the supplemental filing I. MR. HARDY: Thank you. Excuse me for a second. Did you want to consult for a minute. MS. BULKLEY: Did I miss it in there? [Questioning] 362 Board Staff/Consultants MR. BARRIE: Just a second. ---Off the record discussion. MR. DAVIES: Yes, I think we already filed it. It's table 7.7 and in that supplementary filing, page 22. MR. BARRIE: In fact, this is something of an increase because the five-year average was $15-million. MS. BULKLEY: Okay. We missed that. Sorry, about that. MR. HARDY: Thank you. So we don't need to have that information? MS. BULKLEY: Q. That's fine. Can you tell me why it is that these particular stations were selected? It just says in here that these were known to be in poor condition. Can you sort of describe the conditions that resulted in this determination? MR. DAVIES: A. I should explain the difference between this particular program and individual component replacement programs is very much an issue of how we organize the work. We have separate province-wide programs for all the components in the stations but where we find in our review of the condition of a particular asset that there is a significant amount of work needed there, instead of the breakers being replaced under the OCB or Air Blast Breaker Refurbishment Program and the insulators replaced on the Insulator Replacement Program, we will focus attention on a particular station and look at the business case and the alternatives for that [Questioning] 363 Board Staff/Consultants particular station. So having said that, Highbury is the first one. That particular station was providing very poor unreliability to its connected customers. I believe the number of forced outages to those connected customers was significantly higher than the provincial average. The Occupational Health and Safety Act of this province was changed in the '80s which reduced the working clearance that the staff were allowed to work close to energized -- various energy levels of equipment. That has had the impact on us of only being able to work on many components with adjacent equipment out of service. Whereas in the past, when the clearances were less, a tradesman could work on a piece of equipment where the energized -- there was other energized equipment close to him. So it is now against the law to do that. The end result is that we have a number of stations around the province which included Highbury where we could only work on equipment in the low voltage switch yard where the whole of the switch yard was out of service. Now, that depending on the configuration of the system and the customers own distribution system resulted in some of these stations as only being able to do maintenance work, both repair and preventative maintenance work, at periods in the year where the load was very low. So you get to the situation where you may only be able to do maintenance on a Sunday morning and a couple of weeks in the spring and a couple of weeks in the fall. [Questioning] 364 Board Staff/Consultants The end result, therefore, is that as components fail, instead of being able to fix them relatively quickly, you have to defer fixing them until the next valley or the next valley of energy load, spring and fall, which resulted in -- and you're not able to do preventative maintenance except a couple of times of the year. It's the end result that has resulted in accelerated deterioration and customer reliability and also some of the preventative maintenance activity is not being done at the optimum time which resulted in premature aging of the assets. So in terms of Highbury, we had a situation where the customers were getting very poor reliability, customer more than unhappy, through our own knowledge of the assets and asset condition assessment, many of the assets were end of life and the end result was we undertook a major investment in Highbury by building a new low voltage switch yard. Might add that the majority of the expenditures were in 1998 and the expenditures in 1999 are to complete the project. Timmins is a similar situation. Q. Okay. And the other stations were in similar condition, similar circumstances? A. Well, obviously Windsor-Crawford we haven't started yet, but that is a similar situation. Hamilton- Gage is more of an issue of many areas of concern with Hamilton-Gage above and beyond working clearances. [Questioning] 365 Board Staff/Consultants Many of the bus structures are supported on wood poles in Hamilton-Gage. Wood rots, as you can imagine, and we have engineering criteria for assessing the remaining strength of a pole or a wood structure, and basically the wood structures were about to collapse because of rot. The tap changes in the transformers are at end of life. They are a electro-mechanical device that wear with time and irrespective of preventative maintenance they are eventually going to wear out, so the tap changes are end of life. The transformers need regasketing. There is no oil containment around the transformers. The protection schemes are obsolete and not providing the -- the clearance -- the fault clearance time and reliability required of the customer class connected to Gage. So there is -- there is a fair number of issues with Hamilton Gage. I might add the expenditures go beyond the Year 2000, they go out to 2002. And again the question may be: Well why don't you do it quickly? Hamilton-Gage is a very congested site. It's three double-desins in one station. DeReed (phoen), there is not spare land within the fence to rebuild the station on vacant land, so we, in essence, have to spread out the refurbishment activities over a fairly lengthy period of time to still be able to supply the customers. Q. Referring to Table 7.11 on page 93. Actually, probably more appropriately 7.12 where those items are [Questioning] 366 Board Staff/Consultants listed out on the following page, page 94. This is a new program; is that correct? A. What we have not done in the past is address our bulk stations. And what's a bulk station? A bulk station, in our definition, is a station which has 115 kV switch gear and above; whereas a desin station is a connection station, a sub-transformation station, where it's taking two thirty-one fifteen and stepping it down to the voltage, that meets the distributor's needs, twenty-seven six-forty-four kV example. So the bulk stations have not had a program in the past to address their end-of-life so this is a new program. We know from our asset condition assessment that we have number of bulk stations that are in poor condition and the reliability of those stations has serious implications for the bulk system and not just beyond connecting a particular customer like Highbury, London PUC, these stations have significant impact for many customers across the province. MS. SIMMONS (Reed): Q. So if you didn't -- this program was initiated as opposed to doing replacement of individual station components? A. Right. Q. And so somewhere did you -- is there a cost/ benefit analysis that said it's really better just to replace the station because, well -- A. No, I should explain. We are not necessarily -- we're not replacing the station. We are doing [Questioning] 367 Board Staff/Consultants significant work within that station fence. So example, at St. Lawrence, the proposal is to replace the high- voltage circuit breakers. There is no plan for the transformers. Q. Okay. A. So it's -- really what it comes down to is an execution exercise. If we would go to the service provider and say, well, this year we want you or this first six months we want you to replace the circuit breakers, high-voltage circuit breakers, and in the second six months we go to them and say now we'd like you to replace all the high-voltage insulators or the many high- voltage insulators that are end-of-life, the service provider would be moving a crew in, perhaps in the first six months, and then they'd disband that crew, and then six months later they'd come back and start again. So by giving them an integrated package, we are expecting and are getting a more effective, a cost-effective solution from the service provider. Whereas other locations, the only capital work going on at a particular station may be replacement of insulators in a given year so we just -- it doesn't become a bare station project, a bulk station project or a desin station project, that activity is part of the insulator replacement program because that may be the only capital work at that particular station in a given year. Q. So to be in this program, there's a significant amount of work or there's two similar types of [Questioning] 368 Board Staff/Consultants projects going on that there would be a lower amount of outages associated-- A. Exactly. Q. --with doing it-- A. Yeah. Q. --all in one step? A. Yes. For example, the St. Lawrence situation, we've got air blast breakers, 12 of them, air blast breakers at end-of-life. They have significant maintenance costs, very high maintenance costs and unreliability. At the same time, the compressed air systems need major refurbishment, and at the same time we have a large number of high-voltage insulators that meet the criteria to be replaced in the next six months. So it makes sense to look at the solution; for example, if we were to go along and say, well, we'll overhaul the compressors, spend a pile of money overhauling the compressors, and then a year a later or six months later say well, we need to replace these breakers but we won't replace the breakers with air blast breakers, we'll put in SF6 breakers, only you've just poured a pile of money into overhauling the compressors and the compressors are no longer needed. So you're looking at an integrated solution and an integrated program for that particular site. MR. CHOW: A. I would also like to add too, as in some cases, the solution may not be obvious to change life for life. In fact, in a number of cases, maybe the [Questioning] 369 Board Staff/Consultants right thing to do is do something very different because the original need may have changed, the size of station may have changed, where you serve three customers you may be serving one now. So you take a look at all those opportunities and where this is almost like a rebirth of the station if it's the right thing to do. So if you basically, in most cases, you look at ongoing maintenance into the future. You either look at for life for life replacement, or in fact, you just do something different at that point. So it really becomes an optimization issue between sustaining and basically replacing with something different. Q. And when you're evaluating those three options that you just gave, is cost the ultimate driver that makes one program better than the other. I mean cost over some period, not necessarily immediate cost because I recognize there's trade-offs with certain investments that you make where you could simply replace one element and you'd be lower cost now but you'd have higher maintenance costs going forward. What makes the -- how do you ultimately decide between those three options that you just gave me? A. I think the idea, Tim had mentioned about the Oakville case where it's not a station issue as much as a line issue. You start rebuilding a line which we look at. We say: If you were given a brand new situation at that time, would you have built a line again? Would you do [Questioning] 370 Board Staff/Consultants something different? In fact, in the case of Oakville, we did something totally different because looking at where the load is going into the future, what the current need of the station is, and the right decision was, in fact, abandon the line and build a station elsewhere for serving the same purpose. So I think it's important to look at those programs, and see a chance to take a look at at optimal solution, but again, it's not a given that you're going to do anything different, the solution could be ongoing maintenance. I think the issue is to get the information or the asset, find out what you would have down if you continue one path, and would it be more cost effective or better for the long term if you do something different. MR. DAVIES: A. I've got one example, like we have a -- MR. HARDY: I'm just wondering if just before you get to the example, I'm not sure if you're getting the answer you're looking for? MS. SIMMONS: I'm not, but I'd like to hear what you have to say. I mean maybe I'll rephrase my question. MR. DAVIES: A. Okay. We have a particular situation with a particular manufacturer of transformers who will be nameless. Their tap changers are extremely maintenance intensive. Now, we've looked at the cost situation with that, and at this current time it's lower cost to do intensive maintenance than it is to replace the [Questioning] 371 Board Staff/Consultants transformer. It's not a type of situation where you can add a new tap changer to the existing transformer. So at this particular point in time, the expected intensive maintenance is still more cost effective than replacing the transformer. Now, in two years time, the maintenance costs may be accelerating and the cost effective solution at that time will be to replace -- may be to replace the transformer, but we are not putting forward at this time significant expenditures to replace those particular transformers and there is a fair number of them out on the system from one of my favorite transformer manufacturers. Q. So you just used the word "cost effective", and I guess my point is, are you -- is cost effectiveness over some period of time, either five years, ten years, the immediate year, the ultimate decision-maker in deciding how you're going to proceed with this specific transmission issue? A. No, clearly, I mean, public and employee safety is another driver. Environmental -- impact on the environment is another driver, and customer reliability, you know, reliability to the customer is also another driver. So it's not solely driven by cost. MR. BARRIE: A. If you take those at being essential requirements of any solution, they must meet environmental safety regulations. Given all of that, then yes, cost is the eventual decider amongst different alternatives, providing all those other criteria that Tim [Questioning] 372 Board Staff/Consultants just mentioned are satisfied. We would not consider an alternative that did not meet those requirements, but we are trying to minimize long-run costs, yes. MR. HARDY: We are approaching a break now. I'm just wondering if I can get some sense of how long the questions are going to be after the break. MS. SIMMONS: An hour or so. MR. HARDY: An hour or so? MS. SIMMONS: An hour, hour-and-a-half. It just depends on the dialogue that we have back and forth. MR. HARDY: Okay. Thank you. So let's break for 15 minutes. That brings us back at about 2:30 and give all the parties and panels a chance to talk over the break as well. Thank you. ---Recessed at 2:15 p.m. ---On resuming at 2:32 p.m. MR. HARDY: Why don't we bring this session back into order, please? Before we end the day, certainly I'll turn to the panel and if there's any other clarifications of any -- or any other additional information you wish to share, certainly there will be an opportunity to do that. For now we can continue with our Board and Consultants' questions and again, within a reasonable period of time in this later part of the afternoon, I'll certainly open up the floor again for any participant questions. [Questioning] 373 Board Staff/Consultants Why don't we then begin with the Board Consultants' questions, please? MS. SIMMONS (Reed): I think there was a question from one of the stakeholders in response to something that we said and I wanted to give them an opportunity to speak at this point. MR. WHITE: It's Roger White and I'm with Energy Cost Management Incorporated. Q. One of the comments that was mentioned was there was a significant effort made to identify synergy opportunities when work was being done in the station to make sure that the cost effective alternative was subjected to see if there was an overlap or integrated system approach I think was what was used. When you are spending dollars in an environment, are you confident that the asset assessment in each of those locations or sites is sufficiently complete to allow you to identify the synergy opportunities where they exist? MR. DAVIES: A. I think the answer is yes. MR. WHITE: Okay. MR. HARDY: Go ahead. MS. BULKLEY (Reed): Q. We've been focused on the capital programs, specifically replacement or refurbishment for stations. I just wanted to turn to the programs that have been outlined for line components and line refurbishment replacement as well as cable, if we could address all of those together just to sort of [Questioning] 374 Board Staff/Consultants expedite this line of questioning. What I'm looking for is to determine -- to get some information about the future expenditure levels in these areas. Are they expected to continue at the levels that have been forecast for the Year 2000? MR. HARDY: Are we talking about page 98, table 7-14? MS. BULKLEY: Yes. There are several tables actually. 7-14 would be the line components. That's on page 98. Then line refurbishment and replacement will be Table 7-15 on page 101 and the cable refurbishment replacements is 7-17 on page 103, if you could just address all those collectively. MR. HARDY: Also, is it Table 7-18 underground cable as well? MS. BULKLEY: Yes. That's actually just the detail to the previous table, yes. MR. HARDY: Thank you. MR. DAVIES: Perhaps as a point of clarification, in case you may have understood the difference between the component replacement program for lines and the line replacement program, the line replacement program addresses particular circuits where the conductor has to be replaced. When the conductor is replaced, any other replacements are handled at that particular point in time. It doesn't mean to say we totally rebuild the line. If the steel towers are in good shape, there's some work done on them. If the insulators are in good shape, they're not [Questioning] 375 Board Staff/Consultants to address-- only defective insulators are addressed. So we're not talking in that TLR&R program of totally rebuilding the line. We are replacing the conductor and other components that need replacing are replaced at that time. So the earlier - earlier being page 98 - is addressing province-wide programs where only specific components are being replaced and not conductors. And the cable program is a totally separate program; in other words, we're talking underground versus other programs or overhead. MS. BULKLEY: Q. Right. I was just more looking at the projected costs on all those programs. MR. DAVIES: A. Okay. The projected costs -- as I've said, we've addressed specifically in these two years the known problems right now. I could forecast that given the age profile of the assets and the number of assets that we have replaced, that over a ten-year period, we would have to spend more money per year than we're showing in these two years, but we have not done any detailed projections at this time. MS. SIMMONS (Reed): Q. I think that clarifies it. It's hard to recognize here where we're seeing a small bump or whether this is actually a bump that's going to be sustained and so understanding -- MR. DAVIES: A. Sustained is my judgment. Q. Okay. Overall, with all these components and full station replacement -- not full station, but major [Questioning] 376 Board Staff/Consultants station replacements, conductor replacements on individual lines, just understanding that I haven't been involved in Ontario Hydro and certainly haven't studied your transmission system to the extent that I would like and feel comfortable on, to what extent would you characterize any aspect of your existing system to have any sort of redundancies in it whereby you've got a higher level of system facilities that would not necessarily be representative of another similar system? And how are you going about -- to the extent there are any redundancies or a very well developed system, are you maintaining those redundancies or are you looking to where the system may have been invested historically at a very high level? We don't necessarily need to maintain certain things going forward. Is that being addressed as part of this overall capital plan? A. I would say the capital plan, no. The O&M plan, we can talk about how your question applies tomorrow. The question is more applicable to O&M than capital. Q. Okay. Then I think I want to turn to some of the connection programs and some of your development programs. I guess specifically overall, I've reviewed the filing and I do understand that you are proposing to have a network charge and a connection charge and I do recognize that it's going to be a single postage stamp connection charge applicable to all. [Questioning] 377 Board Staff/Consultants And then I look at your program and I see there are a number of significant connection programs and I guess overall I would like to ask you, to what extent is the connection charge impacted by these programs which are included in here in this transition period where they get to kind of be rolled into it as opposed to two or three years from now where these connection types of investments may be directly charged to customers? MR. CHOW: A. We're very mindful of that and, as you said, it is a transition period and one of the philosophies we have adopted for the connection program in the transition period is, we will provide the connection program to meet the customer need but at the same time mindful of the impact on the rate. So in a case where there's insufficient revenue return to justify the cost, we would be asking the customer for contribution. Q. So you're saying -- I'm looking at your supplemental filing "I", page 34, which I believe is probably the largest connection program that I see detailed in your filing and that's the Windsor 150 kV supply to the automotive plants. Specifically, the total project cost is approximately $28-million. Can you tell me, are you saying that there potentially could be a customer contribution associated with this project? A. Not in that case. Q. And that is because the connection revenues from this interconnection will be equivalent to the cost [Questioning] 378 Board Staff/Consultants of the project? A. Oh, yes. Q. Have you gone through that analysis for each of these connection projects detailed in here? Is there somewhere where we can see that the revenues supported by your connection charge are equivalent to the costs of the program? And I do recognize this is capital cost and I can -- I really just need to recover the return and tax allowances on that going forward, but is there -- are there papers where I can see that's true? A. For programs committed, we had to demonstrate to our management the factors that meet those criterias. So for committed work, yes, we have done that, but again, that's to our management. Q. Is there anything that can be made available for the board to understand that the impacts are -- that there are no negative impacts as a result of these programs on the connection charge which you've forecast to -- you know, whatever we're doing with the connection charge, I know that's a question, but I need some greater level of comfort that the revenues associated with these connection projects will recover the cost and not negatively impact any other customers. A. As a process we have done that. I don't know if that's sufficient assurance to you. Q. I would really like to see some more papers. MR. HARDY: I guess I'm hearing you're asking for working papers. That's, I guess, my understanding of what [Questioning] 379 Board Staff/Consultants the question is. MS. SIMMONS: It's fine, you know, the process is okay. Q. I don't know what sort of standards, what sort of discount rate you used in performing this, whether that discount rate is consistent with the cost of capital that you're asking for here. It's those sorts of questions that I'm trying to get a handle on as to understand, yes, this is a transition period, but to the extent this is a significant project and the connection fee is increased 5 per cent to everyone else as a result of it, yes, the charge will recover the cost of this program, but it's higher to begin with. Those are the concerns we have given your proposal to have a single postage stamp connection charge. So I need to have a greater level of understanding that these programs do not have a negative impact on that single postage stamp transition charge. That may alter my recommendation with respect to that charge that's been proposed. So to the extent -- maybe the board can just take this under -- maybe this panel could take it under advisement as to what you can provide to give us a better understanding about the impacts of these programs, the reasonableness of that being recovered through existing -- the projected connection charges for that. A. We'll take it under advisement. Q. Okay. Can you -- [Questioning] 380 Board Staff/Consultants MR. HARDY: Sorry, I just need to be clear, you're taking under advisement -- are we expecting that there may be an answer coming at some point in the future with respect to that particular question? MR. CHOW: We'll consider what's reasonable. And this is only for the Windsor project? MS. SIMMONS: Q. No, I think for the Windsor project, for the Kent project... MR. BARRIE: A. We will undertake a review of the connection that's in here and the possible impact that might have on customers, yes. From a customer connection pool, I guess, is what you're interested in? Q. Right. I am interested in that on the customer connection pool. A. Right. Q. And I guess I'm a bit unclear as to where you would establish a project to be contestable going forward. Would this complete $28-million project in the future be up for bid or could the customer do this entire project on their own? It's hard to understand going forward what aspect of this project would be contestable, so I'm a bit unclear as to whether I would evaluate this full cost of this project versus a portion of it which is part of your network grid responsibilities. A. Yes, and we share some of your uncertainty as to how that will actually pan out as the market opens. Our expectation is though that all connection will be contestable. So typically, we'd expect that the first [Questioning] 381 Board Staff/Consultants possible option would be the customer himself decides to do this connection and we have lots of examples of that already of course, but it would -- we expect it to be openly contestable anyway. Anyway, let us take that under advisement, to have a look specifically at those connections and the impact on the connection pool and those other aspects you raised. Q. Okay. MR. HARPER: Excuse me, I think if this panel can look at the impact of those capital costs. I think the panel coming up next Monday, excuse me, next Tuesday, dealing with rates and cost allocation, they will be in a position to talk about the definition of connections and how that's actually going to work through the transition period. MS. SIMMONS: Okay. That's fine, I think. MR. HARDY: Okay. So rather than me listing information coming forward, I can assume that that question might be better dealt with the Cost Allocation Panel. MR. HARPER: I think the aspect of what the rates are going to cover and how customers are going to be treated during the transition and ultimately covered in the period of open access and what we would consider to be contestable will be covered off next week, yes. MR. HARDY: All right. Thank you very much. MR. D'ARCEY: Just a point, too. On the Windsor [Questioning] 382 Board Staff/Consultants cable job, that is work that is being done by a third party because of its nature and so the majority of that work would be done by an external firm. MS. SIMMONS: Q. But you're going to recover the cost of that in these rates. MR. D'ARCEY: A. Yes. Q. The Windsor auto plants aren't paying for the work to be done, right? MR. BARRIE: A. Contestable can be taken two ways: There's contestable in terms of who is going to own the facility and therefore in whose rate base it goes, and there's the actual excecution of the work which can be contestable in its own right and this is the example where it is, in fact, contestable, the excecution of the work, but it is in our rate base or we propose it is in our rate base, yes. Q. I want to touch upon the interconnection projects and they have been touched upon by many of the stakeholders and I really just want to get confirmation on one thing. And I probably can anticipate your response but I'm going to kind of phrase my question so that you understand my concern. The interconnection projects - and correct me if I'm wrong in any part of this - have been proposed by the MDC and approved by the Minister as part of the market power mitigation and you have been provided something from the Minister that has indicated that these investments should be made to deal with the overall restructuring of [Questioning] 383 Board Staff/Consultants the market; is that correct? MR. BARRIE: A. The specific projects weren't recommended by the MDC. What was recommended by the MDC was a set of market mitigation, power mitigation which required increased interconnections. Now, the specific things were developed by us. We said this is the best way to provide that 2000 megawatts. So, yes, to the general direction coming from MDC and endorsed by government and then the specifics, we develop. Q. Okay. That helps provide some clarification. As to these specific projects, there's a significant cost for these types of investments and I'm sure the MDC recognize that and while not knowing the specific costs but understanding these are large scale transmission projects that are very difficult to pursue under sort of market-oriented conditions, if we're doing these now, did anyone the MDC, the Minister's office, SERVCO, look at real benefits to customers as a result of these projects, that is, whether there would be a reduction in a forward curve for electricity in Ontario as a result of these interconnections? I'm really trying to understand the argument that these interconnections are beneficial to the consumer in Ontario because they're going to presumably promote greater competition and presumably lead to lower electricity costs. Are you aware of anyone who has conducted a study that the Board could look at to try to [Questioning] 384 Board Staff/Consultants understand why the interconnection costs should be recovered by customers via the network charges because of the customer benefits as a result of these interconnections? A. I'm not aware of any. Q. I would kind of open this up to the stakeholder group as well to kind of help the Board understand. Is anyone aware that anyone has conducted any sorts of studies that look at the impacts of the additional 2000 megawatts of import capability on the ten year, twenty year forward price of electricity in Ontario? MR. HARDY: Can I suggest that we'll allow the stakeholder group and the participants to develop their own questions related to that. MS. SIMMONS: I wanted to know whether any of them were aware? MR. HARDY: I'm going to open it up to them so I'll leave it up to them to ask those questions. MRS. FORMUSA: Could I, Dave, just add something here? As we're sitting here today the Market Design Committee is meeting with the Plenary Group and one of the items on the agenda is the market power mitigation assessment and I haven't looked at that myself but it may be that in the material that is ultimately produced by the MDC that we'll see more information and I understand it's coming this month. [Questioning] 385 Board Staff/Consultants So that would be material available to the Board and could hopefully answer some of your questions. But that's the best that I can help you with right now. MS. SIMMONS: Okay. Well, that is helpful. It just kind of clarifies, just because other people were looking for the consumer benefits and I don't necessarily think it's your responsibility to do those studies but I do want to understand the context in which you've been asked to undertake these investments. Q. With respect to the Niagara project, you've discussed that this has additional benefits and, in fact, you categorized it under your Network Program as opposed to where I saw the Interconnection Programs. And a lot of it has to do with addressing concerns you have with loop flow and Lake Erie circulations, it's your term. I guess I'm wondering, being a rates and pricing person, as opposed to undertaking these investments, has there been any consideration to designing alternative pricing schemes or rate schemes so that the customers who are causing the loop on their section pay for it or see the price signals as a result of what they place on your system as opposed to undertaking these investments? MR. CHOW: A. No, we haven't. MR. BARRIE: A. Can I just say that that particular interface is frequently overloaded by loop flow that has nothing to do with any transaction in or out of Ontario. So I'm not sure what kind of mitigation measures we could even have at our disposal. The only one we do [Questioning] 386 Board Staff/Consultants have actually is related to the phase shifters which do actually help to mitigate that. But I'm not sure what else we can do when something is being caused by something going on outside your borders. Q. Okay. I see that. Prior to this decision to pursue the phase shifters as a solution to this, was there any sort of coordinated activities with the New York companies to deal with this or were you involved in the New York ISO development discussions on pricing to understand a better way to deal with this and a better way to attribute the cost of these transactions to the parties that caused it? A. We weren't. I know though the IMO do deal with the New York ISO on a regular basis. But normally the focus there is to relieve transmission overload when it reaches the limit. That is, it's not so much an economic aspect; it's a security aspect. Because that's really the primary concern of the ISOs. So frequently there would be power flow through our system which if it's not a security concern would continue anyway and actually would not be even attempted to be mitigated until security is threatened. But I don't know of any other pricing studies, no. Q. Okay. Well, that's helpful. I'm going to deviate to a couple of the [Questioning] 387 Board Staff/Consultants transmission support programs and in particular there's a couple of programs for pay and HR engineering. And there's a statement made I believe in that section and I'm going to try to find it right here. MR. DAVIES: A. Page 127? Q. Yes, page 127. Actually the statement occurs on page 128. I just would like some further clarification. There's the potential for deferral of the pay and pay re: engineering investment which is currently under review. It makes -- that statement sounds as if this isn't a necessary or immediate concern and I guess I'm wondering can you explain to the Board when that decision will be made and what criteria will you use to decide whether to defer this program? MS. FRANK: A. It's definitely an immediate concern that we manage to pay our people but the question becomes how. And at the moment we have an integrated Ontario Hydro pay system that has just been recently developed in a PeopleSoft System. It's Y2K compliant and throughout '98 has managed to get each of the different pay categories transferred on to this new pay system. Our objective is to get our own pay system and it seems the most efficient way to do that is to actually clone the Ontario Hydro system. However, another alternative would be to continue to use the Ontario Hydro system and just pay for them to [Questioning] 388 Board Staff/Consultants calculate our pay. We are assessing those two alternatives. There's even boundary issue type things. Could you have the generation company calculate the pay for the people who are in your services company? Is that okay or is it not? We also have done some looking outside and seen if there's other pay organizations, one of the banks or something, that might offer calculation of our pay. That doesn't seem too promising because we have a relatively complicated set of collective agreements and most banks wouldn't be prepared to handle those. So the possibilities on the table right now are either cloning the HR system that Ontario Hydro was using or buying the service from them. The definite decision hasn't been made between those two but what we've put forward is the leaning which was we would do the cloning. Cost differential, that doesn't look like it's that much because if we get them to provide the service it will likely not be materially different than if we have the system cloned. But the final assessment hasn't been made. Q. So how are people getting paid right now? A. The Ontario Hydro system is being used at this moment. Q. Okay. But effective April, it can't be used anymore? I've heard December 1st; I've heard April 1st. A. We couldn't -- as of April 1st, we'll have to use the Ontario Hydro system. We could not get this [Questioning] 389 Board Staff/Consultants system - I use the word "cloned" - replicated within the services company business by April. It just isn't possible. So through '98 we're going to have to use the Ontario Hydro system just as one of the de-merger type activities. Then the question is would that be a permanent solution for us or would you build your own separate system. And the full assessment of alternatives and costs hasn't been ironed out yet so that's why it says there is the potential of deferring this if we determine that it's more cost effective to continue to get the generation company to provide this service and if there's no code of conduct type reasons why we couldn't do that - and I don't know the answers to those two yet - then we may well decide that it would be best to defer. Q. Okay. Going back to the Operations Programs and really the bulk of those has to do with your Transmission Management Operations Centre and the amalgamation that's going to occur under your various regional centres. If not for restructuring, would you be undertaking these investments? MR. BARRIE: A. Yes. The amalgamation of the operating centres, in fact, is a continuation of a trend that's been going on for the last twenty years. If you go back far enough, you could find a time when we had 50 operating centres, each operating a station [Questioning] 390 Board Staff/Consultants and a few around it. And over the years we've amalgamated centres. We've had supervisory control systems put in so that each one centre controls more and more stations. With the advent of modern technology, the possibilities were greatly expanded for that and so we would have been certainly doing that regardless of any reorganization. It just makes economic sense to do so. Now, that relates to the territory operating centres or what you refer to as the regional operating centres. In terms of the TOMC, we would still have amalgamated the area operating centres into that one because that made sense. The difference might have been specifically what would we have been asking the TOM Centre to do compared to what it's going to have to do now. When the system control centre was part of an integrated Ontario Hydro - I say was, still is and will be until April the 1st - I think that essentially was a different situation than having an ISO completely independent by statute actually from the Ontario Hydro facilities or in our case the Ontario Hydro Services Company facilities. So I think what it has done -- this is a long way around of saying the TOM Centre will have more accountabilities than it would have had had this reorganization not taken place. But I must emphasis that this is only a small part of the capital programs. Most of the capital [Questioning] 391 Board Staff/Consultants programs in there are to do with the field operating centres which would have happened anyway. Q. Okay. There's one aspect - I'm going backwards - under your telecommunications program and I'm just going to try to find that. I'm looking at page 105 through 107. It says here that you're basically going through a microwave system replacement right now. The total project is $162-million and it's occurring over several years in order to kind of spread the costs there. I just got a sense reading it that this was another one of those things that probably could have been, should have been done previously; is that true? This is kind of consistent with other industry practices? I'm aware of people who have done significant projects like this five years ago or more. MR. DAVIES: A. I make the comment, first of all, that the plan is to spread it over, I think it's seven years, so completed by 2005. Yes, one of them is obviously to minimize the costs in each year, but secondly the availability of outages. We'd have great difficulty in, say, compressing the program into a two-to-three year period because of the outages required to cut in the new equipment. Having said that, the analog microwave system that is -- the part that's being replaced or proposed to be replaced in these two years is phase 2 of program. The analog system to be replaced, equipment to be [Questioning] 392 Board Staff/Consultants replaced in this phase is 30 years old. Industry expectations around 15 years. The equipment is no longer, and hasn't been for many years, supported by the manufacturer. You cannot buy spare parts. We're obtaining spare parts by cannibalizing the components that are taken out of service and doing repeated surveys across North America on the few remaining other locations that have this type of equipment. Phase 1 is in progress right now and the completion date is the end of this year, and phase 2 is proposed to start this year and be completed Year 2000, early Year 2001. Q. And given the changes that we've experienced in information technology and given that you're doing this over a certain amount of time, do you feel that your potentially putting yourselves at risk for the system potentially being outdated by the time the program's completed, and how are you addressing that with your suppliers who may be, you know, giving you -- providing you this equipment that you are installing? A. Well, I don't think there is an issue with the supplier, suppliers in terms of availability of equipment, we clearly have a failure rate, a classic bathtub curve failure rate for the components on the part of the system we're replacing right now, so the individual component failure is rapidly -- rapidly accelerating. So yes, when we look at the O&M program for tomorrow, we will see that there is actually an [Questioning] 393 Board Staff/Consultants acceleration on O&M spending on the existing microwave systems, so in essence, we are having to spend more money in the next few years on the existing microwave system because we are experiencing significantly more failures than we have in the past which is resulting in more O&M expenditures. Q. I guess I wasn't clear. I guess I'm concerned this is a big investment and technology is changing and by the time the system's in there, there will be some better digital system that -- and I guess it's a risk we face, but are -- have you -- in doing -- and in putting in this program, have you talked to other utilities and found out and investigated that the systems that they've put in place, is this consistent with those systems that have been upgraded on those networks, and how does it compare in terms of the expansion capability or increased flexibility going forward? A. Phase 1 that's already in progress is predominantly fibre with a couple of segments being digital microwave. Phase 2 decision has not been made yet whether it's digital microwave or fibre. The costs are very similar, and I think, as you allude to fibre, optical- fibre, we believe gives a lot more flexibility with the changing technology in terms of capacity on those fibres, so although a decision hasn't been taken, clearly, as you indicate, there is some technical -- potential technical advantages of fibre. [Questioning] 394 Board Staff/Consultants Q. And when you make this decision in phase two, will you give consideration to the commercial benefits that could occur in installing a fibre-optic network along your system? I mean, I'm aware of utilities that have gone and offered cable services at the same time that they were up grading their microwave system and it certainly -- A. These expenditures reflect expenditures needed for strictly the teleprotection needs of the transmission system. They do not reflect expenditures needed for any commercial opportunities. Q. But in making that decision, I understand SERVCO is an evolving entity and that could be something -- is that -- is telecommunications a business that's just not even out there that, not something you would consider or is that just too premature to say anything -- A. TNAM is not considering it. OHSC may be considering it but TNAM is not considering it, and these expenditures are based on the costs of digital and fibre and, as I say, the initial capital costs are extremely similar for digital and fibre. But you've also made the point that fibre appears to offer some opportunities for enhancement and capability with changing technology and fibre over the years. Q. I understand the microwave system and I understand the power line carrier systems. Could you just describe the difference between the two and how the two are needed to support your business? A. Yes. What we have is, I think we've shown in [Questioning] 395 Board Staff/Consultants our filing about 256 sites that we need telecommunications into. We have microwave in about a hundred sites. The question is how do we communicate with those other sites? Microwave or fibre can be cost justified when the amount of capacity required between those particular sites justifies the extra cost over a power line carrier. A power line carrier, as most people know, is the sending of signals down the actual power conductor rather than an independent path, but the capacity, the bandwidth that you can use with power line carrier is quite limited, so those parts of the province where the amount of teleprotection signals are quite limited a powerline carrier is quite suitable. And in our particular system, they are predominantly in eastern Ontario and parts of northern Ontario, especially northwestern Ontario and north of The Soo/Sudbury axis, Kapuskasing and Hearst, et cetera. But I should also add that there are many sites that we are using Telco services for communication, but they are not teleprotection communication, they tend to be controlled communication and admin services. So our desin (phoen) stations don't have microwave and we are not proposing to look at microwave or fibre. In many cases with the desin station, Telco services are quite adequate and we use those. Q. Okay. And I assume you make the decision to use Telco or your own just the same way you make other decisions? [Questioning] 396 Board Staff/Consultants A. Exactly, yes. Q. Okay. MR. HARDY: Are we coming to terms with questions? MS. SIMMONS: I'm pretty sure I'm done, but I'm going to take a look and if you could open it up. MR. HARDY: Yes, I'll do that then. Are there any participant questions that might have come up in either the response to the panel or from the questions asked by Board and Board Consultants? Panelists, are there other items that have come up that you wish to clarify or get additional information on. Okay. We'll just give it -- we'll give you 30 seconds or so. MS. SIMMONS: Yes, just give me 30 seconds. Q. I have one miscellaneous question and I'm really uncertain as to whether it's your panel or the panel tomorrow which is the same people and that's -- that's trying to follow where you came up with your working capital number that you included in your transmission rate base. I couldn't tie that off and I just wanted to understand a little bit more about how you came up with that number and the basis on which you derived it. I do understand you didn't prepare the life study looking at things given that this is a new business and whatnot, but whether you want to speak to it today or tomorrow, I would [Questioning] 397 Board Staff/Consultants appreciate some greater detail on that. MS. FRANK: A. Why don't we give it a try today. Q. Kind of a random rate base item that I figured -- A. Specifically, maybe -- your question, please? Q. Let me give you reference to the schedules, I believe they are in section 6. Looking at page 69, line No. 8, mainly your net receivables and other assets, and I see an $88-million item? A. And a think an errata revised to 178. I believe that's for 1999, and 124 for 2000. I think there was an errata that changed these two numbers. Q. And I might be able to derive then. Can you just go through how you actually derived that number for me? A. Yes, I think I can. First of all, what we've got to note is these are mid-year numbers, whereas the numbers that you see in the balance sheet and income statements are end of year numbers so averaging needs to be done. So it would be -- couldn't have derived the 178 from the information that was provided to you. You could have derived the 124 because you have a beginning and end of year to do that, so that's kind of point one. Now, what's in there? What we've included in the net receivables and other assets is the current assets, other assets, and we've subtracted off current liabilities and other liabilities. So that's how we got there. So [Questioning] 398 Board Staff/Consultants that working capital definition takes off the liabilities that we have. We have significant liabilities associated with pay and Workmen's Compensation and that, so we have a relatively large liability number in here. So our working capital is actually negative because of the -- we have very small inventories, relatively small payables, but -- relatively small receivables but large payables, particularly those items. You want more detailed than that? Q. No, I'll take a look at it when I get the transcript and -- A. I'll be happy to take a question tomorrow on this same topic. Q. Okay. A. Okay. MS. SIMMONS: We'll take a look. MR. HARDY: Thank you. Oh, we have a question from Mr. Snelson. MR. SNELSON (AMPCO): Yes. Q. I would like to, I found this figure at page 8 in this morning's presentation quite interesting and, on reflection, there was another point that came to mind. This is the bar chart showing the relative costs of operation and maintenance and capital on a megawatthour-kilometre basis for a number of different utilities. And you mentioned this morning that the capital that is in here is the total capital of spending in the given year. And I believe that makes the measure [Questioning] 399 Participants quite sensitive to whether it's an expanding system or not, and if you have a power system which is supplying an essentially constant load, then the capital spending will be relatively low. And if you have a power system that is growing at 7 per cent per year, then the capital spending will be quite significant. And recognizing that Ontario Hydro, Ontario has had relatively little growth in the last ten years, then I just wondered if you could expand on that? MR. BARRIE: A. Your observation is correct. Q. And that is one of the reasons why Ontario Hydro may look quite good in this comparison. A. I'd have to -- to be fair, I'd have to look at what the other 20 were, and give some kind of assessment as to how many of these were developing and how many were in a more mature state comparable to Ontario. Q. Yes. A. And I think there's a whole range in there. Q. I'm sure there is, but what, I think, we've established is that, at least conceptually, it is sensitive-- A. Yes. Q. --to growth-- A. Yes, it is. Q. --and that Ontario has had low growth in the last ten years? A. Yes. MR. HARDY: Thank you. Other questions from [Questioning] 400 Participants participants? Go ahead, Richard. MR. STEPHENSON (PWU): Just following up on that. Q. I know you said that you can't tell us because of confidentiality concerns who's attached to which of those bars, but can you tell us who the 20 are? Is that something that's available to us? MR. BARRIE: A. I don't think I can. Let me -- let me double check with the... When we participate in this, we signed certain agreements with all the other participants and we certainly can't identify who's performing where. Whether I can even identify who are the other ones, I'm not sure. I'll be here tomorrow and I'll answer you first thing tomorrow morning. MR. HARDY: Thank you. Are there final questions from Board Staff and Consultants. MS. SIMMONS (Reed): I have one more question and it goes back to understanding history a little bit better. Q. Historically, did you ever ask for customer contributions for transmission investments? MR. BARRIE: A. Yes. Q. And if so, how have those been treated in this rate application? Are those customer contributions reflected as a reduction in the net book value of the asset? Where can I assume that they fall in? MS. FRANK: A. That's our general approach whenever a customer gets asked to contribute because they're asking for some standard of service that is above [Questioning] 401 Consultants our normal offering, we ask them to pay the incremental amount and then all we can capitalize is the amount that we have paid. We don't -- we deduct their costs from the costs of doing the work. Q. When it goes on your books, it's already net of any customer contributions? A. Yes, it is. Q. Will that be the practice going forward? Are you going to carry those customer contributions in as -- A. Our current policy is that any customer contributions are deducted from the amount that we capitalize and I'm not aware of any reason to change that policy. MS. SIMMONS: That's all. MR. HARDY: Mr. White? MR. WHITE: It's Roger White, ECMI again. Q. In such cases, is there any contribution made for prepaid maintenance; and if so, how is that accounted for? MS. FRANK: A. I'm trying to think of an example of prepaid maintenance so I can -- I'm not aware that we have prepaid. We certainly -- any contracts that we would have, if the customer owned an asset - we're now more in the distribution system than in the transmission system - but if a customer owned an asset and asked us to do some of the service on it, we've got recoverable work in this program and it would qualify as recoverable work. I can't recall any circumstances ... [Questioning] 402 Participants MR. HARDY: Sorry, could you repeat the last part, please? MS. FRANK: Okay. I was saying that I couldn't recall any circumstance of prepaid work on our system where they prepaid maintenance work, so I'd need the specific example in order to be able to describe the treatment of it. MR. HARDY: Go back to you, Mr. White. MR. WHITE: Q. If you're not taking prepaid maintenance on the incremental component of the line that's being constructed specifically for either a standard of service or an incremental capital cost above what the revenues will carry, then doesn't that automatically produce a shortfall and a reliance on the other customers to support the ongoing maintenance associated with that particular facility. MR. HARDY: The panelist said she was not aware of an example of prepaid maintenance. Are you aware of an example? MR. WHITE: No. Q. What I'm questioning is, is if there is no prepaid maintenance, does that not transfer an ongoing cost obligation to the rest of the customer pool because the customer has requested an incremental service beyond what would be the normal standard? MS. FRANK: A. If your concern is that the customer has required that we put in service additional equipment that the customer paid for and now that we are [Questioning] 403 Participants maintaining that equipment for the customer, we would charge the customer for the maintenance. Q. But not if you took title of it, would you? Say in the case where 100 kilometres of line was built and you took a capital contribution for 25 kilometres of line, should not the ongoing maintenance costs associated with the incremental 25 kilometres of line be borne by the customer either in a prepaid levy or some ongoing levy? MR. BARRIE: A. I'm not absolutely sure whether this is correct, but I think you are correct, that I think the maintenance is not prepaid. I don't know of any examples where it is and then, therefore, as such, yes, it is being levied on all customers. MS. FRANK: A. I think what we should do is offer to take a look at a circumstance like this and get back to you tomorrow morning on it because I'm having trouble recalling or thinking what the policy is and trying to -- you know, what's the example here? I don't know that we -- tomorrow morning? MR. HARDY: Yeah, I've noted the question. Are you going to be here tomorrow morning? MR. WHITE: Yes. MR. HARDY: Okay, fine. I think that question is clear from what I've heard. So is there a follow-up question to that? MR. WHITE: No. MR. HARDY: Okay. Thank you. Are there any other participants or panelists 404 that wish to ask questions that have not asked questions of this panel? ---(No response). Seeing none, are there any other comments that the panel wishes to provide before we adjourn? ---(No response). Okay. I wish to thank participants, Board staff, Board consults for all the questions. I would certainly like to thank the panel for your responses and we're adjourned until tomorrow when we will pick up the OM&A panel. Thank you. ---Whereupon, the Technical Conference proceedings were adjourned at 3:22 p.m., to be reconvened on Tuesday, the 12th day of January, 1999, at 9:00 a.m. 405 I N D E X o f P R O C E E D I N G S Page No. Overview (Facilitator) 239 Introductions 240 PRESENTATION: by Dave Barrie 240-256 by Myles D'Arcey 256-259 QUESTIONING: by Consultants and Board Staff 260-279 by Participants 279-329 ---Luncheon [11:58 p.m. - 1:05 p.m.] 109 by Consultants and Board Staff 331-344 by Participants 345-353 by Consultants and Board Staff 353-398 by Participants 398-400 by Consultants 400-401 by Participants 401-403 Parties who questioned: J. Gibbons . . . . . . . . . . Pollution Probe D. Poch . . . . . . . . . . . Green Energy Coalition E. Robertson B. Bacon . . . . . . . . . . . OCAP R. Stephenson . . . . . . . . Power Workers' Union J. Fisher K. Snelson . . . . . . . . . . AMPCO R. White . . . . . . . . . . . Energy Cost Management Incorporated JB/LJ/LL [ Copyright 1985].