RP-1998-001 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 Tuesday, January 12, 1999 commencing at 9:05 a.m. --------------------- TECHNICAL CONFERENCE "Transmission OM&A" VOLUME 4 --------------------- F A C I L I T A T O R : DAVID HARDY Board Technical Staff 407 A P P E A R A N C E S DAVID HARDY ) Board Technical Staff KIRSTEN WALLI ) JAMES WHITEMAN ) in conjunction with: MICHAEL HARRIS ) Reed Consulting SUSAN SIMMONS ) ANN BULKLEY ) Ontario Hydro SUSAN FRANK ) Services Company Inc. DAVID BARRIE ) [SERVCO] MYLES D'ARCEY ) TIM DAVIES ) 408 ---Upon commencing at 9:05 a.m. MR. HARDY: Okay. Welcome back to the continuation of the rate technical panels. I'm Dave Hardy. I'm facilitating the application. Is there anybody here who has not attended an earlier panel? ---(no response) Okay, great. Let's see, I'm going to have you introduce yourself in a minute. Let me explain in a little more detail a synopsis of how we're proceeding. Basically this is an informal session. My role is simply to try to keep the agenda on track and also be concerned with the process and fairness. We've been proceeding through a series of issues that's been tracking or following the Ontario Energy Board Issues List that was prepared and distributed before the new year. We have the final panel today on transmission, then we move into -- or actually, we shouldn't say that. We have a panel on transmission today on OM&A and that follows on the 18th with transmission PBR. We move into next week with transmission related to cost allocation and rates and distribution panels as well. Today we do have a follow-up to one of the questions that was asked yesterday. I will start by again having the SERVCO panel introduce themselves and then, Dave, you can lead with your question and then your presentation and I'll then turn to Board consultant staff Overview 409 (Facilitator) and have them pose their questions at the outset and then we'll proceed through the day as long as we have questions to ask of the panel. So welcome, panel. And Dave, can you introduce your panel once again and then deal with your first response? MR. BARRIE: Okay. Good morning. Essentially we have the same panel as yesterday except we don't have Bob Chow with us, the director of system development in that he has little or no impact on the OM&A program. So could I ask the panel then once again to introduce themselves? MS. FRANK: I'm Susan Frank from wires integration and regulation. MR. D'ARCEY: Myles D'Arcey, engineering services. MR. DAVIES: Tim Davies, asset sustainment, TNAM. MR. BARRIE: Dave Barrie, general manager of transmission network asset management. MR. HARDY: Okay. I'll just add that there are extra copies of the handouts yesterday at the side for those of you who didn't get one yesterday and you have handouts as well that are at the registration desk. Dave, I believe you're going to bring us -- begin by bringing us up to speed on a response to one of the questions that was posed yesterday. MR. BARRIE: Yes. One of the questions yesterday was concerning the benchmarking study that I had Overview 410 (Facilitator) referenced, the ICTP study. The issue was on identification of participants and the confidentiality surrounding that. So we checked last night with the people involved with the specific benchmarking initiative. The ICTP is the industry ad hoc standard for transmission comparison. The 1996 study had 21 participating transmission companies or transmission subsidiaries. These 21 represent many of the major stand-alone transmission businesses in the world. The confidentiality agreement do not allow us to divulge the identity of the participants; however, in the spirit of the question that was asked, that is, the extent to which they are mature businesses or developing businesses, I can indicate the following: The participants include four from North America including OHSC, eight from Europe, predominantly western and northern Europe, five from Australasia and four from our other parts of the world. 75 to 80 per cent of the participants in our view are mature transmission businesses in mature economies. The remainder are experiencing growth from developing economies or expansion cycles. I would just like to finally say, many mature transmission businesses do have significant O&M and CAPEX expenditures. MR. HARDY: Thank you. Would you like then to proceed with your presentation, please? Presentation 411 (D. Barrie-SERVCO) MR. BARRIE: Thank you. PRESENTATION BY MR. BARRIE: Okay. Today we are following up on yesterday's review of the capital programs and we're going to speak with about the transmission revenue requirements which, of course, focuses on our OM&A expenditures. This chart provides an overview of the total transmission revenue requirement. What I propose to do today is, I will deal with the first two items on that list and I'll ask Susan to cover the remaining items, they being primarily financial items. While I have that slide up -- I want to come back to the OM&A one because that is clearly the predominant number there, but while I've got that one up, I would like to deal specifically with the transmission performance incentive line. It's a small number as you see in the big context, but it does seem to generate a lot of interest, so I thought I would try to deal with it up front. The TPI really has its genesis back in the -- three or four years ago when Ontario Hydro internally restructured into business units and the intent was to try to incent the various business to act in a commercial manner. TPI was one of the mechanisms for doing so and was introduced specifically to incent the transmission business to carry out activities that benefit the other participants in the electricity industry. In this rate order, it is really a place order in Presentation 412 (D. Barrie-SERVCO) that there is a flow in and a flow out of cash and doesn't really affect the rate; however, Panel 4 will get into the specifics of how they will actually factor into the rate order. So I won't deal anymore with that. I would just like to tell you what is behind it. It really covered three major elements in its development. The first one was generation bottling caused by transmission constraints. Now, clearly the transmission system, we cannot be held accountable for all transmission constraints because there are just naturally constraints occurring on the system all the time. What we're trying to focus in on TPI is those elements of constraints which can be traced to actions taken by the transmission enterprise. So for instance, if we were to take an outage, a transmission outage, that caused some generation bottling, then we would be penalized for that. So it would drive us to minimize our transmission outages and, in fact, to have our transmission outages at times when they did not cause bottling, which is -- makes eminent good sense and it would just try to incent us by having a financial payback for doing so; similarly, for transmission losses. Now, I want to make very clear, there are a lot of losses on the transmission system as was indicated to Panel 1 and I popped up and made that response for Panel 1 of about 4 per cent. It comes to something like $160-million. That is not covered in TPI. Again, TPI was looking to cover that part where the transmission business Presentation 413 (D. Barrie-SERVCO) had some control over it. And again, if I could refer to outages, if we take a transmission line out, there are increased flows on parallel circuits and losses go up. So we're able to calculate the impact of our the outage program on transmission losses. So that was also factored into TPI. The third element were internal energy efficiencies. The transmission business itself in its activities uses energy. So again, we have been incented to reduce our own energy consumption. So there were the three major elements of TPI and that's really how we arrived at a number like 23- or $24-million. That was the order of magnitude of TPI looking back and it's our suggestion of a place order of the kind of thing going forward, but how it will look going forward will be discussed by Panel 4. Okay. Now, I'd like to go back to the OM&A now and could I have the next slide, please? Just a reminder of something we touched on yesterday, the word "sustainment" is chopped off the top there. There we are, sustainment strategy. Our basic sustainment strategy is life cycle optimization of the existing assets. We spoke a little bit about it yesterday. I think it's more in context today because it covers both OM&A and capital. Essentially it involves inspection and preventative maintenance, corrective maintenance and a lot of asset condition assessment. I've also flagged up here environmental Presentation 414 (D. Barrie-SERVCO) initiatives because they do form a major part of the work program that you're about to hear about. I'd like to stress that going forward, the first bullet and the fourth bullet become of primary importance to us. Our strategy relies upon more rigorous inspection and condition assessment. Based on this more rigorous assessment, RCM uses this information to make better decision-making and in general less invasive maintenance. So we're looking to know more about the condition of our equipment and make more intelligent decisions about what maintenance is required. When we've done all that, we're really faced with a decision as indicated at the bottom. We can continue with maintenance at some higher or lesser level or we can initiate component refurbishment and replacements or wholesale system replacement at end of life. On a couple of programs you heard about yesterday when we were reviewing the capital, they indicate the component refurbishment and system replacement. So this is just trying to fit all three together. And there is a tradeoff between them. As I think we indicated yesterday, if you don't do sufficient maintenance, it can reflect in having to do either more maintenance now or an accelerated component refurbishment and replacement or have to do end-of-life replacement earlier than you would have to. So I think we touched on that yesterday and I did want to acknowledge that there is relationship there between all those elements. Presentation 415 (D. Barrie-SERVCO) As I did yesterday on the capital program, I don't propose to go through each element. It is in the submitted material and of course we will be very happy to answer questions. I just wanted to hit the major trends. So again we've broken up the total OM&A program into and this time we've broken it up into six categories as per this chart here, the primary one being the OM&A sustainment. As you can you see there's increase between 1998 and 1999 and if you look at the details of the programs you can see that this is primarily due to programs associated with environmental issues. It then drops off between '99 and 2000, and this is primarily efficiency, primarily in unit costs. Those are the principal trends in the OM&A. The Development OM&A is the costs of -- actually my own direct costs of running my business and they are constant over this period. The Operations OM&A, there is a drop between '99 and 2000 and that is caused by the control centre amalgamations that I mentioned yesterday. By amalgamating control centres we're able to get by with less operating staff and that's reflected in a reduced OM&A. Recoverable work is this constant and I think Myles spoke a little bit about that yesterday but we can speak more. Our grants in lieu, this is our expectation of the way the province will apply the proxy tax regime. And Presentation 416 (D. Barrie-SERVCO) transmission support again an increase between '98 and '99 and this is again due to setting up the new company, demerger activities which falls off again in the year 2000. Now, then I just want to refer to some documents you already have to try to supplement what I've said. In speaking about the sustainment strategy, I would refer you to the appendices C and F in the main filing. C is the capital O&M strategy overview and F is the maintenance of transmission asset strategy which I think gives a more full description of what I've just touched upon. More detail of the OM&A programs and the trends can be found in Tables 9.2, 9.3 and 9.4 of the main filing. And the rationale for year-on-year between '98, '99 and 2000 in more detail is provided in supplemental filing B of the December 23rd supplementary filing. So with that I'd like to ask Susan now to cover off the other items on the chart. PRESENTATION BY MS. FRANK: Dave has already covered off the first two items which talk about the operating costs, the OM&A and transmission performance incentive and I'm going to talk about the other items on this chart which are depreciation, financing charges, taxes. These are items that are basically driven out of the policies and the financial architecture that was discussed on Panel 1. What I'm going to try to focus on is a bit of a change over the two years. So let's start with Presentation 417 (S. Frank-SERVCO) depreciation and you notice a slight increase in depreciation. This depreciation is reflective of our depreciation policy, the depreciation rates and those come under the Depreciation Review Committee. The slight increase is due to the increase in assets associated with the restoration of the capital and some of the interconnection capability that we discussed yesterday. The financing charges reflect the volume of the debt and the rate on the debt. The rate was quite extensively discussed on Panel 1 and it stays constant over the period but the actual amount of debt increases as the assets increase. So the increasing assets gives increasing debt and as you can see a slight increase in the financing charges. We move on to taxes. Taxes were also discussed on Panel 1 and they fall out of the proxy tax rate of the 44.6 per cent and the capital tax rate. The net income reflects the level of equity and the ten per cent return that has been developed as part of the financial architecture and extensive discussion of that was held in Panel 1 as well as supplementary filing being prepared and offered to you from Cathy McShane. When that gets to the total costs in net income that we require, we subtracted off revenue that we get from other parties, external revenue of recoverable work, as we've labelled it. This work relates to a range of activities, items Presentation 418 (S. Frank-SERVCO) such as telecom work for primarily other parts of Ontario Hydro, work on the Genco switch yards, some secondary land use revenues, as well as the recovery of overheads within the OHSC business that were fully assigned to the wires business and we're recovering from the non-regulated business or our Board costs. You notice when you get to the bottom line that the productivity savings that we're finding in 2000 reduce the OM&A program and this slightly overrides the increased costs associated with higher assets and higher fixed asset charges. So overall we have a small reduction in the revenue requirement in 2000 from '99. Thank you. MR. HARDY: Does that complete the presentation? MR. BARRIE: Yes, I just wanted to slightly amend something I said. When I referred to my own OM&A and it was shown against development, that is only my own development OM&A. I also have costs in the sustainment portion and in the operations portion, so my total costs are spread across the three elements: sustainment, development and operations. And in all cases my own costs are constant. MR. HARDY: Thank you for clearing that up for us. I think then we're ready for our starting questions and I'd like to ask Board Consultants and Staff, perhaps starting with Staff to reintroduce yourselves or [Questioning] 419 Board Staff/Consultants introduce yourselves in one instance and then we can begin with the questions. MS. WALLI: Board Technical Staff, Kirsten Walli. MR. WHITEMAN: Board Staff, James Whiteman. MS. SIMMONS: Susan Simmons from Reed Consulting Group, consultant to the Board. MS. BULKLEY: Ann Bulkley with Reed Consulting Group. MR. HARDY: Okay, who would like to begin? MR. WHITEMAN (Board Staff): James Whiteman. Q. I'd just like to ask just a couple of questions on this recoverable work and I'll apologize if you've covered some of this yesterday. Pages 138 and 1389, recoverable work, there's 1999, 49-million in both years. I was just wondering, are there contracts in place for all the different projects, all these different works that are done for external parties? Is that the reason the numbers are the same in both years? Table 9-2 is what I'm looking at. MS. FRANK: A. The recoverable work as I was just saying covers a variety of items and for the pieces that relate to work on switch yards for our generating companies or on telecom or other pieces like that where there's indeed a work program that's carried on year after year, there would be service level agreements with those parties. Some of the other ones that I put in there would [Questioning] 420 Board Staff/Consultants be the class associated with making secondary land revenues. This is Wendy's and those kind of places have a parking lot on our right-of-way and we have a contract with them to gather some rent associated with having that parking lot on our right-of-way. So there are contracts for that type of work as well. Q. And I assume there are revenues to the company associated with each one of these projects? In all cases... That's a yes? A. Yes. Q. Thank you. And in each case, these revenues you are satisfied that they at least equal or they exceed the costs so that there are items in the revenue for each of these different projects? A. Our practice for pricing any recoverable work is that it fully covers all the costs, the operating costs associated with it, any equipment that we'd have to use and the interest and depreciation on that equipment as well as a margin. We've looked at commercial enterprises and what a reasonable margin is on that work. And if you want to go more into margin we can talk to Myles about it. But we do have a margin on it for bit of profit on it as well. MR. WHITEMAN: For each one of them. Okay, thank you. Those are my questions. MS. SIMMONS (Reed): Okay. I would like to ask you a question in response to a comment you made that - and I'm sorry if I'm not quoting [Questioning] 421 Board Staff/Consultants you exactly - but productivity improvements offset the increase in revenues associated with increased interest expense and financing charges on your higher asset base in 2000. I guess I'm trying to get a handle on where there are productivity improvements from 1999 to 2000 that you've just indicated. When I see that there's a 55-million reduction in OM&A and I see that half of it is relating to transmission support decreases and half of it appears to be from OM&A and you've attributed the cost increases to environmental activities, environmental expenses. So I guess I'm trying to understand where the real productivity improvements are occurring in this period or if they're not occurring in this period, over what period do you expect to see them occurring? MR. BARRIE: A. Okay. Could we take it in two parts. One part was the drop in transmission support between '99 and 2000 and the other one was the drop in sustaining OMA between 1999/2000. I'm referencing Table 9.2. Those are the two principal drops that I think you referenced? Q. That's correct? A. Okay. So, Susan, do you want have a shot? Q. I'm trying to understand, are the drops real productivity improvements or are the drops really reflective of single one-year cost increases that are just unique to the demerger or unique to a certain [Questioning] 422 Board Staff/Consultants environmental requirement that you need to meet in this year? A. Well, Susan tries transmission support and Tim can try the sustaining line, okay? MS. FRANK: A. The transmission support item does have items in it, Susan, that you're talking about in terms of demerger activities that are higher in 1999, that are one-time costs and really aren't productivity driven. They're -- you've got to build a process or yesterday we were talking about building a pay system. Those costs that are indeed one time. So that's certainly a major part of why we have got '99 so high in transmission support. But there are also productivity improvements that we believe are possible and we've included in 2000 and they would relate to centralizing some of the functions, having one fixed asset accounting group rather than having many fixed asset accounting groups, one tax group, one treasury. These items, as we centralize them, get the process in place we expect we can do it with fewer people in the future. The HR systems that were mentioned yesterday, self-service employee systems that are being developed in capital will result in fewer HR staff as we can have employees access the data about their HR status themselves rather than having people standing by phones ready to answer questions, so that there are productivities in this area as well as the one-time costs associated with setup in 1999. [Questioning] 423 Board Staff/Consultants Q. Okay. I just want to follow up with you. Help me to understand, are you saying then that the 2000 costs technically should be higher and the fact that they just are becoming closer to the 1998 level costs, however accurate those are, is reflective of productivity improvements? A. Yes, that is indeed what I'm saying. The 1998 costs, there were many functions that are being done in transmission support in 1999 and 2000 that were not done in '98. The items that I've talked about, like the treasury, the law functions, were not in the '98 numbers, they were held at Ontario Hydro corporate and did not make their way into this transmission support number. So while it may appear that the reduction doesn't take us even back to the level in '98, the '98 number did not reflect the full work program that's necessary for a stand-alone company. Q. Okay. Any of these -- you just talked about many of the different programs at transmission support. Is there any documentation you can provide us that gives us -- quantifies the productivity improvements that you expect to see as a result of some of the increased costs we're experiencing in 1999? Can you quantify that aside from this drop that I see from '99 to 2000? I can't follow where there are demerger costs and where there's one-time costs as a result of the activity redesign that needs to be done for transmission support? A. Are you looking for a breakdown as to what [Questioning] 424 Board Staff/Consultants costs we have eliminated; is that what -- Q. Well, to the extent you're doing certain activities and you're consolidating certain things because you've just told me you're achieving productivity improvements, I just don't have a sense of magnitude. Are we saving, you know, $5,000 or $5-million and that's what I'm trying to understand. We've got a significant cost increase in 1999. Maybe if we started where there was a breakdown in that cost increase between demerger and reengineering. You know, we use the term demerger very loosely and I'm not really certain whether these are legal fees that you're paying as a result of demerger, whether it's simply a replication of activities for duplicating the pay systems? I'm not sure what demerger means and maybe we should start right there. A. Okay. Start with the last part of that question. MR. HARDY: Sorry, I think perhaps we can-- MS. SIMMONS: I think that's correct. MR. HARDY: --just sort this one out. There was a request for, I'm hearing, if there were any cost breakdowns first, and then we move on to your question about the definition of demerger. MS. FRANK: A. The productivity savings -- yesterday I gave you some information that suggested that there were in the order of, I believe I said, $35- to $40-million of incremental savings in 2000 over 1999 and I did characterize some of those as being associated with [Questioning] 425 Board Staff/Consultants the OHSC function and services savings. A share of that that would be OHSC function and services savings would be, I'd say, roughly $10-million. If you want more detail than that, I'm going to have to take it under consideration. MS. SIMMONS: Okay. Q. Well, let's go on and have you help me understand when you -- when the term "demerger" is used, what are you referring to and what are these demerger costs? Are they simply the costs that are in here? Are there some other sort of costs that I'm not aware of or haven't been clearly defined to me? A. The demerger costs are all included in our filing so it's not like they are costs that we haven't incorporated in our revenue requirement. They reflect one-time activity that primarily relate to setting up processes associated with separating the company. Some -- I always fall back on the pay because I think it's so obvious that if you have a new company, you've got to have a pay system. You've got have processes to track how you're paying everybody. We didn't have those processes for a separate pay system so we have to design the processes. You've got to come up with all your policies and review all your policies and see if they're still appropriate. I think on Panel 1 when we were looking at the policies that we are currently using which are attached in Appendix H, we indicated there were a few [Questioning] 426 Board Staff/Consultants cases. The words on these policies were no longer appropriate for a wires company. They recovered items on training, for example, that related to a nuclear business which we obviously don't have. So some of the demerger activities are setting up our own set of policies, reviewing all those policies, and making sure that they are specific to our business. And those are the two issues that come to the top of my mind as demerger or I -- you know, if you want more, I can -- Q. Are there any financial fees or banker fees or legal fees associated with this demerger? A. There's certainly costs, legal costs, associated with setting us up. The legal costs were formerly not part of transmission support, they were Ontario Hydro costs. Now, when we put them into the wires business, we have legal costs and there are special one-time costs in terms of setting up this organization and getting all the contracts and everything established, yes. Q. So you're saying there are costs that were incurred by Ontario Hydro prior to that and that you'll be allocated a share of those and those are reflected here? A. But there's the ongoing portion that's reflected here and then there's also the one-time incremental costs associated with setting up the new business. Q. All right. I would like to turn it over to [Questioning] 427 Board Staff/Consultants Myles and have him describe to me -- I think I understand a little bit better about transmission support. Dave made a statement that the increase from 1998 to 1999, some of that relates to environmental programs and then I see the OM&A falling back down closer to the 1998 levels and I'm really trying to understand, is this a result of productivity improvements, increased efficiencies as a result of things that you're doing now and changing the way you do maintenance, or is this really just seeing the one-time blip that's a result of a couple of programs that are one-time non-recurring types of -- or recurring at a periodic rate expenses? MR. DAVIES: A. Okay. I'm refer you to page 141, table 9.4. Okay? So unfortunately this doesn't show the 1998 numbers but I believe our supplementary filing does provide those '98 numbers and I can read them off if that helps you our you may have that other numbers, those set of numbers in front of you. If I look at station maintenance, preventative and corrective maintenance '98, it was 50-million; PNC was 18, contaminated lands was 7, remedial component refurbishment was 4, environmental management was 3 with a total of 81, I believe it comes to. So the question, I believe, was how do -- why does it go up from 81 to 104 and then why does it come down to 86? Okay. Now, as you can, in terms of station maintenance and PNC maintenance, the 1988 to 1999 is [Questioning] 428 Board Staff/Consultants relatively flat, a small increase, and I can talk to that separately. The two numbers then drop down. And the question is why do they drop down. Predominantly that's unit cost efficiency from our service provider. We are expecting our service provider to come back in the Year 2000 with significant costs, cost savings for units of work -- a unit of work. If you look at contaminated lands, we can talk separately again about that, but there is a substantial increase there over '98 to '99 and 2000, and that is a ramping up of a program. Remedial and component -- Q. Before you go on-- A. Yeah. Q. --ramping-up of a program. Was there a change in environments regulations-- A. No. Q. --that produce this program? A. No, it was a change in, if you like, corporate strategy, putting a lot heavier emphasis on our existing properties, proactively evaluating the potential contamination over existing properties and potential contamination caused by ourselves on neighboring landowners' property. Q. Okay. Please continue. A. Remedial and component refurbishment going from 4-million up to 8-million and then back to 6. That predominantly, the increase is basically due to catch-up maintenance caused by a lack of funding in the past. [Questioning] 429 Board Staff/Consultants I can give you examples of what's in there. Environmental management is initiatives taken basically to be a good environmental steward, a stewardship of our facilities and particularly to our equipment rather than the land and a number of environmental issues that we are faced with with our equipment which we feel we have to address, which again, I can go into details. Q. Why don't you, at this time, go into a bit more detail on your remediation activities-- A. Okay. Q. --and environmental management. A. Okay. The remediation activities, we have, let's call it -- you'll notice it says 'remedial and component refurbishment'. We've had an ongoing program for many years providing mid-life major overhauls of air blast breakers. This program, I think -- I think separately I think we've said, I think that we have about 340 air blast breakers. Air blast breakers, we have an expectation of a life of an air blast breaker of approximately 40 years and these are high voltage air blast breakers, typically 230 kV and 500 kV. The air blast breaker contains many gaskets and 'O' rings. Our experience and the experience of many other utilities is that material, those 'O' rings and those gaskets, typically lasts around 20 years, typically. After that, you start having many leaks resulting in many outages of the equipment. It becomes unreliable to operate. So you have to go through, if you like, a [Questioning] 430 Board Staff/Consultants mid-life major overhaul where the breaker is totally stripped down and all gaskets and 'O' rings are replaced and any other problems corrected. The air blast breaker then has a further life expectancy of another 20 years after that major overhaul. So as I say, we've had a program for a number of years doing mid-life overhauls of these breakers. The numbers embedded in these do not reflect an increase over our previous expenditures. It's a continuation of a previous program. The vast majority of those breakers will have had their mid-life overhaul at the end of Year 2000. We have, I think, as I recall, 14 breakers that will be due for a major overhaul in about 2003, 2004, but we would expect in 2001 and onwards a ramp-down for a couple of years in that area. So that reflects a part of -- and that's predominantly the 4-million that you see in 1998. So the balance of the 8-million reflects things like catch-up activities where we have not been able to address known problems in the past because of lack of funding. These are design deficiencies with equipment that needs to be modified. They reflect known problems with equipment from -- known failure modes and equipment that components have to be replaced. The replacement doesn't justify capitalizing the expenditure. It has to be O&M. So there's a number of types of equipment, predominantly breakers that fall into that category. Another part of that category expenditures is we [Questioning] 431 Board Staff/Consultants have major heavy equipment that when we have to move a piece of equipment because it fails, predominantly transformers, historically we've used the railroads to move the equipment into stations. As the railways have rationalized their rail lines in Ontario, there are fewer and fewer rail lines to -- adjacent to our sites. So when we have transformers fail, we have to move replacement transformers more and more by road. And as you move transformers by road, they have to go over bridges. The Ministry of Transportation of Ontario has regulations regarding moving of heavy loads over bridges. Now, our ratings of transformers are such that we require when a transformer fails, to replace that transformer relatively quickly, 10 to 15 days. That requires us to quickly move the transformer. To get a permit to move transformers over bridges, you need to have available design calculations for those bridges. So a large chunk of this expenditure reflects doing engineering calculations to prove that the bridges have the ratings to satisfy the MTO for a transportation permit. I might add, the majority of the expenditures are contracted out to consulting engineering companies. Q. Is there another way you can move the transformers; is it cost effective to move them by air? A. Well, we're talking about a transformer that weighs 100 tonnes or 150 tonnes, so ... helicopters don't really have that capability yet. Q. Yeah, okay. Before we go into anymore [Questioning] 432 Board Staff/Consultants details, I had a number of sort of general questions that I think probably could be answered by you or could be answered by Dave. I'm really trying to get a better handle on understanding the tradeoffs you make between pursuing ongoing maintenance and deciding it's time to refurbish and replace a specific component or line or numbers of stations component. And I understand that there are various criteria that you use, but I really don't have a handle on how you make this -- how you perform the financial analyses to determine it's time to replace it or, no, we can continue sustaining a slightly higher level of ongoing maintenance for the next three years, five years. Can anyone speak to a bit more detail as to how you decide to continue with maintenance versus refurbish replacement or system replacements of any specific components? And if it's different by, you know, by components, we'd like to understand that as well. A. I think it is different by components. For broad areas, we look at: 1, does the component, the device, still able to provide the technical functionality that it was originally installed for? An example would be a circuit breaker - can it interrupt the full current that it's expected to see or can it not? So that would be one area where we would be looking to replace the breaker. The second area, are the maintenance costs accelerating and are the costs such that on a net present value basis, it would be a lower cost to replace the asset [Questioning] 433 Board Staff/Consultants with a new asset with different maintenance cost versus continued intensive maintenance? I think I provided an example yesterday on a particular type of tap changer that we're faced with. Q. Right. If I can just stop you hear, when you perform that net present value analysis, can you just describe how that is done - what is the time period, what is the discount rate, how does it vary depending on what asset we're looking at? That's the heart of my question. I really don't understand how that's performed and why -- when you get down to making that decision, how is that done? MS. FRANK: A. For any investment decision of significant dollars, we do a net present value analysis of the alternatives that are considered. The net present value would typically attempt to look out over the life of that asset that you are adding or the decision, so ten years would tend to be a minimum period we'd look at and we would sometimes go up towards the 40 years. By the end that period, the numbers become relatively soft. The discount rate that we'd use would be our weighted average cost of capital, is that we typically would use for this because that is, indeed, how we're financing our assets. So it is a combination of the 60 per cent on the interest and 40 on the withdrawn equity. Q. Okay, that's fine. If you can continue, you've gone through a couple of different criteria that you use. I wasn't sure you were completed. [Questioning] 434 Board Staff/Consultants MR. DAVIES: A. Okay. There may be safety on environmental issues, that the device is no longer safe to operate because it's deteriorated or it's beginning to create significant environmental impact and the problem cannot be addressed through maintenance. It has to be replaced. And the fourth issue where there's opportunities by taking the asset out of service to replace an asset with that -- requires or provides a lot more economic opportunities. An example would be that perhaps where we're replacing SCADA systems, operating central amalgamations where the technology being replaced provides or allows us to have a significant reduction in employee costs. So those would be four areas. Q. Okay. On page 22 of appendix C of the transmission rate application, I just want to confirm that I understand what you just provided to me in response to my last question. In this diagram here, there's a box here 'multi-criteria life assessment'. Were the factors that you just went through with me a description of that process? A. Yes. Q. Thank you. I want to turn to -- I believe it's page 62 of appendix F. So I think the appendix just -- the pagination just keeps continuing. A. Sorry, page? Q. Page 62 which is also in appendix F of the [Questioning] 435 Board Staff/Consultants transmission application. There's a statement on line 13 that these assets - 12 and 13 - these assets have been built and expanded over a 90-year period resulting in the use of a variety of designs and technologies. I want to understand a bit more about what you people have characterized as the design standard of the transmission system. And you've made some references throughout the panels that, you know, in some areas, the system is weak and that's for a certain reason and it's very costly to have a very robust system in the northwestern areas. Are there any areas of the system that you would characterize now based on your current design criteria where you'd find that there are redundancies in the existing system or that the system was built with a design standard that exceeds your current design standard; and if so, how are you dealing with the continuing maintenance of those facilities or components which may currently exceed your design standards for a specific area of the system? MR. BARRIE: A. Susan, can I just clarify the use of the phrase "design standard" as it's used here and-- Q. Sure. A. --as you've expanded upon? Q. Please do. A. I'd like to distinguish between system design - that is how we plan the system, how many lines we install, how many stations and where and whether we put [Questioning] 436 Board Staff/Consultants dual lines in or single lines - if I could just call that system design, and I think that's what you're alluding to-- Q. I am alluding to that. A. --and this phrase here which tends to be focusing on equipment design. And equipment design drives you in a certain direction. If you have a lot of different kinds of equipment, you have to apply different kinds of strategies and that's the context in which it's used here. Q. Okay. A. So Tim will be happy to try to answer questions on equipment design - at least I hope he is - and I will attempt to answer questions on system design or I can recall Bob Chow to the stand. Q. Okay, if you could get back to system design and then we'll move to equipment design and respond to my question where it's unclear to me, and you know your system better than probably anyone else here, whether you would characterize any element of your system design or any element of the system having been developed or built or constructed at a level which exceeds what you would do today. And I'm just trying to understand whether we're maintaining facilities that we probably don't need to or the standard at which they were first put in place provides the ability to meet a triple contingency that exceeds what current utility practices say is reasonable and ... if you can just try to address those concerns. [Questioning] 437 Board Staff/Consultants A. Okay. If you look at our overall integrated transmission network which would be where your question really focuses on, we built the 500 kV backbone of the system to accommodate really the nuclear program. It allows major transfer of power east and west across the province depending on the availability of the nuclear stations and whether we have major import or export from the neighbouring utilities. And we have had examples over the past few years where we could point at major flows across the system in either direction depending primarily on those two variables that I just spoke about. At any given time, we can look at the 500 kV network and find there is very little flow on some of the critical interfaces because it just happens to be in balance at this point in time. It would be easy to leap to the conclusion then that you don't need the degree of redundancy that is built into the system and that would be true for that particular instant in time. But if we're going to retain that flexibility to be able to cater to all these different eventualities, then I would suggest that it is not an overbuilt system in that sense. Now, one can point at particular places in the system. We've built two double surrogate 500 kV lines out of the Bruce nuclear development. There is also a significant 230 kV lines out of the Bruce development based upon being able to get eight nuclear units, the output from eight nuclear units on to the system. Clearly, if we at some future date don't have [Questioning] 438 Board Staff/Consultants eight nuclear units at Bruce, then one could argue that you may have too much transmission coming out of the Bruce complex. We have not at this point in time officially declared any such plant permanently mothballed. So at this point in time, I've gone a long way out of saying that I don't think we have any significant overcapacity on the system. We certainly don't treat any equipment on the system differently in terms of saying that it is overly redundant and, therefore, we don't need to maintain it to the same level. We certainly have not reached that point. The whole 500 kV backbone is maintained to similar standards across the whole province. I'm not sure if I answered your question. I think I understood where you-- Q. It's helpful, it's much more helpful to understand that. I guess you kind of focussed on some major elements of the system and I do follow the design and why it was constructed in that way. Maybe I'm getting more to Myles. MR. BARRIE: That's Tim. MR. DAVIES: It's Tim, by the way. Q. I'm sorry, I do apologize. Tim, when you're getting down to smaller components and you're going through your asset condition studies and assessments and potentially you find that a certain area or maybe there are no cases where there are [Questioning] 439 Board Staff/Consultants additional components or components that you wouldn't normally put down and maybe we're getting to a design and the fact that you said there's different equipment manufacturers and different types of equipment and different designs at which you establish a particular station and built and constructed that station; to the extent that you find that the design of the station isn't as what you would do today, are you slimming down or scaling up or scaling down when you're maintaining those assets or you're deciding to: we need to refurbish and replacement; we're not going to design the station to be at the same level as we did previously. I don't know if you follow my question but... MR. DAVIES: A. I think our expenditures are driven by many, many factors and I could give some examples and perhaps that may be the easiest way. The relay protections -- we have relay protections, I think over 12,000 protection schemes in the province. Eighty per cent of those are electromechanical. A quarter of those 80 per cent were installed between 1920 and 1950, so they're over 50 years old. And we have protection schemes that are from the 1920s still in service on the 115 system. Those protection schemes are obviously electromechanical. In general, they have been robust. They are labour intensive to maintain and at this point in time because they have mechanical linkages, et cetera, they are wearing out and the availability of spares is rapidly [Questioning] 440 Board Staff/Consultants deteriorating and support from spares from the manufacturers is obviously long gone. So that obviously influences, when that relay can no longer function to its intended requirement influences our replacement program. It also by replacing it with microprocessor relays reduces the ongoing maintenance requirements for calibration and functional testing. Are circuit breakers reliable, robust? Clearance times of all circuit breakers that were designed 40 or 50 years ago are not of the level that you get with a modern FF6 or vacuum breaker. Again, depending on the functionality required of that particular station, you may require clearance times using the breaker that are changing because of system requirements or individual connection requirements. So that would be a factor of driving you to look at replacing that breaker. Cap bank switching, in the past we've used oil circuit breakers for cap bank switching, low voltage cap bank switching as the duty cycle on low voltage oil circuit breakers is very intense on cap bank switching. It may be used three or four times a day. Labour intensive, it's economically justifiable when the breaker comes to end of life to replace it with an FF6 breaker because of the savings you're going to get through maintenance costs. In many other cases, oil circuit breakers are quite adequate for their duty and when they come to end of life we remanufacture them and put them back in place. So [Questioning] 441 Board Staff/Consultants the functionality hasn't changed but we can expect another 40 years of life from that oil circuit breaker. So what I'm trying to say is there are many drivers that dictate whether we leave the device in-service, whether we replace it with a new technology or we refurbish the existing technology. Q. That's helpful. MR. HARDY: We'll continue for another fifteen minutes or so. MS. SIMMONS (Reed): Okay. I have a few more general questions. Q. Your Appendix F goes through and detail your strategy behind the maintenance of the assets. And you go into detail in section 6.0 on page 65 on that strategy. And I would like to just understand a little bit more about the relationship between -- there's a lot of proper names and proper terms in this document, a lot of reference to various systems and I'm just going to ask some really general questions and I apologize if they sound a little bit elementary, but I'm really trying to understand a little bit more and you're helping me today with how you're going through this. The PMO process, is that something that's a part of all reliability-centered maintenance programs? I wasn't clear what that did and how that was integrated into the reliability-centered maintenance program. MR. DAVIES: A. If I can respond. Reliability-centered maintenance is a philosophy. It [Questioning] 442 Board Staff/Consultants isn't necessarily a strategy; it's a philosophy. So perhaps there's a little bit of confusion in the terms that all parties use. In our particular case, our program is called the PMO program, using RCM philosophy. Now, if you step back and look at how historically we've maintained assets, ourselves together with, I would have to say, all utilities, electrical utilities, historically have used a time-based maintenance program. In other words, every so many years you do something to that asset, maybe every six months, every year, every four years you do something to that asset. What we've done in line with some other utilities is we've stepped back and said there has to be a better way of doing maintenance on our assets and we've looked at all the failure modes of assets, of individual assets and we have many, many thousands of different types of assets. We've looked at the failure modes. We've looked at the critical failure modes that will prevent the asset doing its function and we've said what maintenance activities could prevent those critical failure modes. That's a fundamental issue in RCM so that's where you're going to get the philosophy. And we've stepped back and said, what preventative maintenance activities should we do to prevent those critical failure modes and the non-critical failure modes we've done an assessment and in some cases we've stopped doing any maintenance on those particular [Questioning] 443 Board Staff/Consultants sub-components that no longer -- it's not economically justified. So, perhaps as an example, transformers have radiators. Many radiators have auxiliary fans - these are 110-volt or 220-volt fan motors drive these individual fans. The historical maintenance approach would be to go and do some preventative maintenance on those fan motors and those fans themselves and bearings, perhaps every six months or every year. Having done an assessment, we've to come to the conclusion that the failure of one fan for a particular transformer may not de-rate the radiator and therefore de-rate the transformer. So it makes economic sense to stop maintaining the fan, the fan motor. We let it run to failure. However, some other categories we've identified it's very important to do some either diagnostic or monitoring activities, for instance the circuit breaker itself, and do some intrusive maintenance where the diagnostics indicate that it's time to go and look at the breaker. So I don't know whether that gives you enough information or you need more. Q. That gives me enough. Now, it's the asset management group; is it those people who are developing these standards and deciding and studying these areas? A. Yes, with some support from the internal [Questioning] 444 Board Staff/Consultants energy services group, Myles' group, and in some cases external consultants. Q. Okay. There's reference to a number of different systems and I assume these possibly may be database systems or they may be process systems and I'm not clear on. If someone could just speak to -- on line 15 there's reference to the OATIS system - maybe that's not how you pronounce it - and on line 24 on page 66 there's reference to the CMMS system. Are these information technology systems? MR. HARDY: Having an ear for acronyms here, can you give us the full title of OATIS and the other? MS. SIMMONS: Q. The Operating Administrative Trades Information System, on lines 14 and 15 on page 66, and down at the bottom the Computerized Maintenance Management System, the CMMS system. If you could explain or someone could explain how these are populated and what they are and how they support your job? MR. DAVIES: A. Yes, we have over 3,000 technical standards, procedures, directives that document required technical decision-making, technical standards, engineering standards and these are collected in a system called OATIS and it's an information system that provides dial-up into a server or a CD-ROM for people in the field using laptops. The other system is basically a work management system which we've recently -- well, OHSC has recently [Questioning] 445 Board Staff/Consultants introduced, that allows the scheduling of work and the reporting of work into a computerized work management system. MR. D'ARCEY: A. We've recently purchased a product called the Passport system which helps schedule work and resources and it also has included to it linkages back into job procedure documents with regards to how work should be done. Q. That's the system here or that's another system you're referring to? MR. DAVIES: A. It's our acronym for a product that's been purchased in the marketplace. MR. D'ARCEY: A. That is the product. Q. When you say it links back, does it link back to any of these other -- does it link back to your OATIS system? A. The models that are referenced from the reliability-centered maintenance component which dictates what work has to be done references the work procedures which are embedded in OATIS. Q. Okay. Now, were these systems that were always part of the transmission business unit or did Ontario Hydro previously use similar systems for all of their energy assets? MR. DAVIES: A. In terms of OATIS in the long distant past the hydraulic generation business which was not linked with fossil and nuclear in an organizational sense, shared with the transmission system the precursor [Questioning] 446 Board Staff/Consultants to OATIS. OATIS is, if you like, the IT portion that carries the documents. The documents, in many cases, were shared with the hydro-electric generation part of the business but several years ago the systems were totally separated. MR. D'ARCEY: A. We're currently going through a process with all of our documentation to separate it from the Ontario Hydro component. There's also a great deal of overlap between the transmission side of the business and the distribution side of it with similar components and requirements. So we're consolidating our documentation, which is, on the distribution side, was a DOJADS component which is the same thing as the OATIS. Q. Okay. That's helpful. One last question with respect to...in this section, in Appendix F. On page 77, once again we see the word "benchmarking". I want to understand whether Ontario Hydro participates or performs other benchmarking aside from the benchmarking charts that you gave to us yesterday and that you've referred to this morning as part of that study, that industry ad hoc group study that you participate in. Are there specific manufacturer benchmarking or equipment benchmarking that is done as part of your reliability-centred maintenance program? MR. DAVIES: A. I think there's multiple facets of benchmarking. One is the performance of the [Questioning] 447 Board Staff/Consultants components. Another is how efficient is the service provider, et cetera, in executing units of work. Another is the type of work that you do. We contribute to the CEA who operate a database for component reliability but I think, as I indicated yesterday, it's limited to transformers, switch gear, high voltage switch gear, and lines. It doesn't get into other sub-components. Our benchmarking per se in terms of beyond the CEA is limited to the overall performance, as Dave showed some slides yesterday. But we do have fairly extensive consultation processes with individual other utilities where we share experience. But we don't have the experience formally documented. We meet fairly regularly, our staff and members of IEEE, task forces, CIGRE task forces, DOBLE workshops where there's a fair amount of exchange of ideas and information approaches in those forums. MS. SIMMONS: Thank you. MR. HARDY: Thanks. Why don't we take a break now. I have about ten after ten so we'll be back about twenty-five after. At that point we'll open up the questions to other participants, then we'll follow-up with additional Board questions. We'll break now until about 10:25, 10:30 or so... ---Recessed at 10:10 a.m. [Questioning] 448 Participants ---On resuming at 10:30 a.m. MR. HARDY: Why don't we then begin this part of the review of the application with participant questions. And who entertains the first questions? Go ahead. MR. BACON: Bruce Bacon from OCAP. Q. I just want to talk a little bit about losses and understand a little bit more and I brought it up with Panel 1 and I just want to ask some questions related to losses. The transmission performance incentive, it's related to losses as well and you mentioned it was the cash flow in and out. I'm just trying to understand what you meant by that? In your presentation you mentioned -- MR. BARRIE: A. Yes. That statement was applicable to the whole of TPI, not just the losses. Q. Okay. A. So it's really a place holder. It's actual treatment in PVR. I'm not precisely certain how it will be actually handled. We wanted to indicate that we believe it's appropriate for the transmission provider to have an incentive to drive this kind of performance, so it's a place holder in there. As far as I'm concerned the way we are now it's just cash in and cash straight back out. But in a performance-based rate main, we believe there should be some kind of incentive based on the kinds of things I've talked about to drive appropriate behaviour from the transmission provider. [Questioning] 449 Participants Now, Panel 4 will get into some detail as to how it will actually work in practice. I'm afraid I -- that's about all I can do. Maybe Susan can add a little more. MS. FRANK: A. When we talk about the flow, cash in and cash out-- Q. Right. A. --what we're saying is we believe our revenue requirement should incorporate the charges we believe are appropriate for this, so that's how the cash comes in through transmission revenue. And the cash out component would be the people who have their generation bottled in generators should get a payment for the loss that they've incurred. So that's where the payment would go is actually to the generators who weren't allowed to get their product to market because our line wasn't there. Q. Okay. So it would be a cash -- it is a cost to the customer is what you're saying? A. Yes. Q. Okay. So within that transmission performance incentive, how much is for losses, incremental losses, management of incremental losses? Any idea what that would be? MR. BARRIE: A. It was something like 6-million of the 23-, 24-million was associated with losses. Q. Okay. A. Of that order, anyway. Q. Now, with regards to the average losses, now [Questioning] 450 Participants I think I understand this, that it's actually in the uplift charge with the IMO, it's not sitting in your -- it isn't in the transmission revenue? A. That's correct. Q. And the rationale there is, as least from my understanding of it, is that when they move to L&P, the L&P process will be putting the incentives in place to handle the losses; would that be correct? Is that a correct understanding? A. Are you asking is that why it's in the uplift now? Q. Yes. A. The reason it's in the uplift now is because the way we are organizing the electricity industry in Ontario with the IMO, independent generators, and a transmission provider, all of whom have an impact on losses, the uplift is really the only place one could reasonably put it. We have, "we" in the transmission business, have control of a very small part of that total loss picture. So to put it in our revenue would be inappropriate given the way we are organized. Q. Okay. I can understand that. A. In other jurisdictions, where there is a single entity, such as National Grid Company in Britain, for instance, their losses are factored right into National Grid's revenue and they do take accountability for the total loss picture because everything is within their control. We have chosen not to go that way in [Questioning] 451 Participants Ontario so it really has to go into the uplift. Q. So since it is in the uplift, since it is in the IMO uplift, what is the -- I'm trying to understand, what's the review process to review the IMO charge? I know it's not part of this proceeding, I understand that, but if you want to review losses, what is the process in order to do that? A. I think I can only reasonably speak to what you could expect the transmission provider to do about losses. The rest I have my own opinion on, but I don't think it's part of this hearing. Q. Does anyone have...? It's in section 18, 19. Okay. I'll check that. Thanks. Okay. The last question with regards to losses, if there is a need to reduce losses and then for some reason someone, the IMO or in coordination with you people, determine that you need to do something to the system to handle losses, who's responsible for those facilities; is that the transmission group that would put those in -- those losses into the rate base? Are those capital charges to handle losses into the rate base or is that a responsibility of the IMO? A. I don't know. MS. FRANK: A. It kills him to say it. MR. BARRIE: A. You had to drag that out of me. Q. I didn't mean to drag it out, I just wanted to understand -- A. Well, I mean, I would like to stipulate why I [Questioning] 452 Participants think it's a reasonable thing for the transmission provider to do towards losses. We do do a lot of activity to minimize losses. Q. Right. A. But our impact, as I indicated, was 6-million out of 160-million, just to give you the amount that's within our control. So we, for instance, when we're reconductoring a line or putting a new line in, we might use, you know, low loss conductors to reduce the losses on the line. But that's the sort of extent we can do. We can minimize our outages, which again tends to reduce losses, but all of that might amount to what I've indicated, six in 160. A far bigger influence is what generating stations are available on a particular day and what transactions are being carried out which we have absolutely no influence on. MR. HARPER: Excuse me, Bruce, the fifth panel that will be up here -- well, as Dave said, it sort of doesn't fall totally in the purview of transmission, there should be some people there that might be able to pursue that question. MR. BACON: Q. So I guess in summary average losses are handled by IMO, incremental losses are handled by a transmission group, and we'll find out about capital in the Panel 5; is that...? MR. BARRIE: A. Parts of incremental losses are dealt with by the transmission group. [Questioning] 453 Participants MR. BACON: Okay. Thank you. MR. HARDY: Can I just for the record, Ms. Formusa, you've referred to section 18, 19. Just share with us what you were referring to there. MRS. FORMUSA: I think what Bruce was getting after was he was going to review these uplifts and whatnot and all I was pointing to was sections 18 and 19 of the Electricity Act which talk about the fees that are being charged. Now, I'm not sure if the uplifts are going to be included within that, but certainly the OEB has the authority to approve fees being charged by the IMO. Again, Panel 5 can talk about specifically the direction that the Market Design Committee is going in this regard, but certainly fees, and I'm not -- what I'm not sure about is whether uplifts will be included within that and within the budgets that the OEB will be reviewing for the IMO. MR. HARDY: Okay. Thank you for that. Are there other questions? Richard. MR. STEPHENSON: Richard Stephenson for the PWU. Q. I want to come back to the maintenance issue. I remember some time ago in one of the OEB hearings, I think it was at a time -- at the time of the Hydro restructuring in '94 -- '93/94, about something being introduced called "predictive maintenance" which is something that I never understood at the time, but is -- is what you're referring to here as the PMO, is that the same thing as predictive maintenance or is it an outgrowth [Questioning] 454 Participants of it or is it something different altogether? MR. DAVIES: A. I'd characterize it as an outgrowth. Predictive maintenance is a subset of PMO. Q. And your material says that this was introduced relatively recently and I gather it's an ongoing process? A. Yes, PMO is being introduced this year, is the first year of it being introduced. Q. And I guess what I'm interested in is presumably, at least one of the purposes of PMO is to allow you to, in a sense, do either the same amount of effective maintenance with less resources or more effective maintenance with the same resources or whatever? A. The latter. Q. The latter. A. Yeah. Q. Well, that was going to be my next question. Is there any -- are you able to provide us with any information about, essentially, the incremental efficiency savings by virtue of the adoption of this program? In other words, what it would have cost you to do, in essence, the same amount of maintenance on whatever maintenance strategy you're pursuing prior to the introduction of PMO? A. The previous strategy had evolved over a number of years. The most recent version would have -- with the funding that we had in 1998, we were only able to achieve approximately 65 per cent of the work that would [Questioning] 455 Participants be needed to fully implement the previous strategy. So by moving to this new strategy with a small increase in funding, 2-million on station maintenance, et cetera, we are able to hundred per cent implement the new strategy, so there is a significant savings by moving to this new strategy over the previous strategy. Q. You've been able to provide us some element of historical linkage in terms of your contrast between your planned expenditures and past expenditures. What I guess I'm curious in is if you can assist us further in terms of -- in constant dollar terms, what the magnitude of your maintenance program is as compared to what the grid company did historically, say, through the '90s? Are you trending up? Down? Or if we take five years ago or even if you took ten years ago, are you at about the same level, higher or lower? A. In the late '80s, we were close to 90 per cent funded for our previous strategy. Since then, because of constraints on the integrated company, the amount of funding required for maintenance has been reduced every year and it's trended down to 65 per cent, as I said, on average, 65 per cent of the strategy. Q. In absolute dollar terms -- A. I don't have that in front of me, quite frankly. Q. Okay. But I take it that -- you've framed it in terms of percentages -- A. If you look at the numbers in 1999, we're [Questioning] 456 Participants talking about -- well, in 1988 I said 50-million for station maintenance. Given that funded 65 per cent of the previous strategy, you can work backwards to what would be 100 per cent funding. Q. I take it, it's fair to say there are less absolute dollars today than there would have been back when you were at 90 per cent or whatever that is? A. Yes. Q. Okay. MR. D'ARCEY: A. There's also another variable associated with that and that's from the service provision side of it and that's a reduction in the unit cost to provide those services. So we are in through the service level agreements under an obligation to reduce the costs of delivery so which it effectively provides more maintenance at a reduced cost over the next two years. Q. In terms of -- just so we can understand in terms of service providers on this, for both OM&A and capital, sometimes that's done by society and PWU represented employees and sometimes by building trades' represented employees; am I right about that? MR. DAVIES: A. That's correct. Q. And in terms of building trades' represented employees, sometimes those are actually employed by Ontario Hydro through your hiring hall; is that right? A. That is correct. Our collective agreement requires us to use construction workers out of the EPSCA union halls. Whether they're employed by Ontario Hydro or [Questioning] 457 Participants employed by EPSCA contractors is beside the point, from the union's point of view. So we meet our requirements of the collective agreement either using Myles' organization to execute the construction work or using an external EPSCA contractor. Q. That was my next question and that is, yeah, if you -- another option, aside from Hydro employing these people directly, is for you to contract in an EPSCA contractor to do all or part of the project work; is that right? A. And that's correct. And I think as Myles said, the cable job that we talked about at length yesterday in Windsor, a substantial-sized development project, the intent there is to use an external EPSCA or a contractor to do that work. Q. Right. MR. D'ARCEY: A. I think it's also important to clarify -- I mean, we're talking about operation maintenance dollars here. Predominantly most of that work is done by PWU work forces. EPSCA traditionally is more on the capital side of the... Q. I understand that, but there's some overlap in both cases. A. Yes. Q. PWU does some capital and building trades does some OM&A. A. There are overflow agreements between the PWU and the EPSCA agreement which allows some cross-over, [Questioning] 458 Participants that's correct. Q. And just to come back to this issue about the EPSCA contractors. In that case, even when you're using an outside contractor to do the work, in terms of your unit cost on labour, it's identical because it's the same agreement I believe. MR. D'ARCEY: A. That's correct, the unit cost on labour would be the same. Q. You may obtain either expertise or savings in terms of the contractor's own management fee and project fee in terms of their organization of the work, however, in terms of -- as compared to Hydro doing it themselves? MR. DAVIES: A. Correct, or additional costs, as the case may be. MR. STEPHENSON: Indeed. Okay, that's all for now. Thank you. MR. HARDY: Just for the record, it's EPSCA, Electrical Power System Construction Association, is it? MR. DAVIES: Correct. MR. HARDY: Thank you. The next question. Go ahead. MR. WHITE: Roger White, ECMI. Q. I don't know whether this is the right panel to ask the question, but it's one of philosophy in terms of how SERVCO operates because it may help the OEB in terms of their understanding of the relationship between SERVCO and the Municipal Electric Utilities. When you decide through either operation or [Questioning] 459 Participants maintenance or capital to transfer costs between Disco and SERVCO -- or Disco and Transco within the company by a decision to either do less distribution maintenance and rely on the transmission system or to do less transmission maintenance or capital and rely on the SERVCO, who makes those decisions and what criteria is used to make those decisions? MR. BARRIE: A. In terms of the development of both our capital program and the OM&A program you've heard about today, that tradeoff that you've just mentioned simply does not occur, because as far as we're concerned in the transmission business, OHSC distribution looks just like a municipality. So a tradeoff simply doesn't occur the way you've just described it anymore than it would when we're looking at system design for the supply of Toronto Hydro, Mississauga Hydro or anyone else. There are often things you can do on a distribution system to mitigate some capital requirement on the transmission, but to suggest there's any difference between the way we do it for OHSC distribution and all the municipalities is quite wrong. Q. I wasn't suggesting there was a difference. I was asking for clarification as to how those decisions were made between Disco and Transco and who makes those decisions and what criteria is used to make the decision. A. Okay. Typically, the planners, when they're looking at some system reinforcement requirement, would deal with the distribution people if there is a [Questioning] 460 Participants distribution alternative and we do exactly the same with the municipalities when we meet them. So the criteria, the bottom line criteria, is, what is the overall minimum cost? Q. That would include both capital and OM&A, present value of OM&A? A. The example I alluded to was a purely capital item, but I don't see the plan in the OM&A context. Q. If you're spending capital dollars, that's the up-front portion, but when you commit to capital dollars, there's an ongoing stream of OM&A that flows out of that decision. A. Okay, in that context, yes. MR. WHITE: Thank you. MR. HARDY: Any additional questions, Roger? Are you finished your questions? MR. WHITE: Fine, thanks. MR. HARDY: Other questions? Mr. Snelson? MR. SNELSON: Ken Snelson representing AMPCO again. Q. When I was talking to the Policy Panel last week, we did some comparisons of the 1998 business plan OM&A to the OM&A that is proposed in this application. And one of the components to the difference that was identified was due to the reversal of provisions or the resurrection of costs, as I prefer to call it, that were written off to 1997 rates. And in general terms, I believe the figure that was mentioned was somewhere around [Questioning] 461 Participants about $100-million as being due to the change in this financial policy and a large proportion of that, I would presume, is due to the transmission OM&A and some part is due to the distribution OM&A. And the first question is: How much of the OM&A cost difference between 1998 business plan for 1999 and the OM&A proposed from 1999 in this application is due to the change in this financial policy? MR. BARRIE: A. Okay. It falls largely into two areas that I'm going to ask the other panel members to speak on because they have the details. So it's really, Susan and Tim, between you. So Susan, would you like to kick off? MS. FRANK: A. I think I'll start, Ken, with the amount of money that you're talking about. The 100-million, roughly, that Panel 1 referred to was, indeed, a combination of distribution and transmission work. The distribution work included in 1999 is $59-million worth of OM&A dollars that was formerly identified as provision. You've made a question -- let me just seek clarification on a question. Were you wondering what was in the '98 as well for similar or what was...? Q. The question is primarily on the difference between the 1998 business plan for 1999 and the 1999 amount being requested in this application. So if 59-million is due to distribution, then presumably -- I doubt the number was exactly $100-million but something [Questioning] 462 Participants approaching $40-million must be transmission. A. Well, maybe there was an error. Likely I misspoke. 59 is transmission and there's actually -- 61 is distribution in 1999. In 1998, these items were covered in a provision and were not part of OM&A. Q. Yes. A. And the amount in total for transmission and distribution in '98 would have been just over the 100-million of provision work that was done in '98. The breakdown between transmission and distribution in '98 was 26-million on transmission and 80-million on distribution. Q. Okay, that's helpful. I was wondering if we could look at the breakdown of the OM&A program which I believe is shown in tab B of the supplementary materials, page 2, and that shows -- there's a table at the top of the page showing the year-over-year work program analysis for transmission. And I think what I've heard is that -- and this has been restated to put back into the 1998 the provision work, I believe. A. Yes, it has. Q. And so the $373-million that is shown in 1998 for OM&A includes $26-million of transmission provision work that you've just told me about. A. Yes, it does. Q. And the 1999 figure of $441-million includes $59-million-- A. Right. [Questioning] 463 Participants Q. --of transmission work. A. Right. Q. And I'm wondering if you can tell us how that provision work is distributed between the OM&A work programs at this high level that is shown in this table where it's broken down into sustaining development operations, et cetera. A. I'm going to do a first cut and then hand off the work program over to Tim, but the first cut that I could do for you is to say that there's $29-million worth of work that Tim is very familiar with in terms of the breakdown between what's in sustaining development area and then there's -- Q. Is that 1999 or 19 -- A. 1999. Q. in 1999, okay. A. Yes. And then there's another 13 that possibly Myles will want to speak to in terms of provision type work that network services is doing. And then the remaining amount, the 17, is in the transmission support area. And if you want to get to that one, I'd be likely the best person to speak to those. Q. Okay. So you're saying there's 29-million divided between sustaining and developing? MR. DAVIES: A. No. It's all sustaining. Q. All sustaining, okay. And there is -- I missed the middle number. The 17 you say is to do with transmission support. [Questioning] 464 Participants MS. FRANK: A. And the 13 is out of the network services group and I believe that it gets spread throughout the work programs, but I'd like Myles to... Q. So the 17 is spread through. A. The 13. Q. The 13 is spread through, sorry. And I'm wondering if -- whoever is best to speak to it, to speak to the rationale for the -- first of all, why were these costs written off against 1997? Perhaps we could go through the different categories and explain the rationale for that. A. I think those are two different questions. Ken, I think if you want a justification of why the work is necessary, then we should go to Tim and Myles, but if you want to know the provision in '97 and why a provision was made and why the costs are now in our program here, that's a -- which of those two questions are you asking? Q. I think there's probably three. I think if you want to break it down that way, there may be three questions. A. Okay. Q. So the first question is, why is the work necessary? And I'm quite happy to hear the answer to that and I think it would help us. The second question is why was it written off in 1997. I think a third question is: Why is it being reinstated in 1999? Maybe we can start with the first one. So what [Questioning] 465 Participants is the work and why was it necessary? MR. DAVIES: A. Okay, perhaps I'm in the best position to talk about the actual work itself. If we look at the Stations Program and we're looking at Table 9.4 on page 141 of the main submission. We look under the Contaminated Land line showing 18-million, that is a substantial increase over previous years and, as I mentioned earlier, the corporation has made a decision to do a detailed survey of all its transmission sites to establish whether there is contamination as defined by the Ministry of Environment and the degree of contamination and to determine if any of that contamination is moving off-site to neighbouring properties. We're doing it because we feel it's appropriate as an environmentally sensitive property owner. The expectation is that we will have done a detailed sampling of every site that we have, all stations, by the end of the Year 2000 and that we anticipate that we will have to put remediation programs, clean-up programs in place for a number of sites and those clean-up programs are also built into these cash flows, 18-million and 16-million in 1999 and the Year 2000. Q. That's one component. A. Yes, and if we look at remediation and component refurbishment, that contains a number of things. It contains -- as I talked about, we left some money in there for ongoing air blast breaker refurbishment program [Questioning] 466 Participants but there are a number of activities correcting design deficiencies -- known design deficiencies on equipment that is basically catch-up work that should have been done in previous years that hasn't been done. And also I talked at length - most probably at too much length - about moving transformers over bridges. That's the catch-up engineering work that we feel is appropriate to charge to provisions. So there is funds in there, in that line to cover those type of activities as well. In terms of the environmental management, that 7-million and that 6-million, again we're talking of catch-up on re-gasketing of transformers. We have, as I mentioned, about 1,400 transformers on the system of which about over 700 are power transformers. We have a fair number of those transformers leaking oil. They are leaking more than they should be and we need to expend dollars to re-gasket transformers to catch up on work that should have been done in the past and again incremental funding has been put in there to cover that. We are accelerating the phase out of PCBs and the decontamination of PCB wastes. And again we're legally, by legislation, not required to decontaminate destroy PCB waste but we feel it's an appropriate environmental stewardship role to do and it also reduces our risks. As you know PCB wastes, if they were on fire create a major public health hazard, so as an appropriate [Questioning] 467 Participants risk management approach we are accelerating the decontamination of PCB waste and there is, as we know, technology available that allows that to be done now. So by the end of 2000, it's our intent that all PCB waste that we currently have on our sites will be destroyed. So again that is built into that line on environmental management. Another line there is, we have a number of transformers, not very old. Like the typical expectation of a transformer before end of life is 50 to 60 years. We now have a number of transformers that were purchased in the 1980s where the radiators of those power transformers are deteriorating rapidly, corrosion, poor paint application the first time, corrosion. And if they are not given repairs and repainting we will have to replace the radiators at significant cost. So the refurbishment or the repainting and repair of those transformers, I believe it's eight transformers in the first year and eight transformers in the second year, are built into the environmental management programs because we see it particularly as an oil spill issue. As they deteriorate, we have a lot of leaks through the metal. So there are a number of programs that are incremental beyond our regular PMO maintenance program that we've put in place that are, if you like, catch-up activities that would go under the heading, if you like, Provision-Type Catch-up Work. [Questioning] 468 Participants Q. Why wasn't this work done at the appropriate time when the -- you're saying this is catch-up work, so why was it allowed to fall behind? A. Basically we did not have the funding to do this type of activities in the previous number of years. Q. Okay. Now, does that cover the sustaining part of the program? A. Yes. Q. And there are some other components that you referenced me to and perhaps you can describe roughly what they are? MR. D'ARCEY: A. I'll quickly to talk to the 13-million that was referenced by Susan. The majority of that again is along similar lines to what Tim had referenced within the service delivery component of it, site assessment for contaminated lands. The offices, the operation centres which we work out of were used as storage depots over the years and so from a due diligence component we're doing a site assessment associated with that and then based on the results of those site assessments any associated remediation is included in that. There's also a provision within that for restructuring costs, relocation with regards to staffing related to restructuring of the organization and moving staff. There's also re-skilling and the re-tooling of resources associated with that. [Questioning] 469 Participants Q. There was $17-million referenced with respect to transmission support? MS. FRANK: A. The 17-million incorporated, I would say, process and management redesign-type issues. So some process re-engineering work that's under way to ensure that indeed we do have industry best practice is included in the 17 and some of the performance measurement-type activities, getting those performance measures in place and the information systems that would allow us to measure the performance on an ongoing basis is the other element that incorporates the 17 and it's in the transmission support. Q. That's in the transmission support and that would have been covered off under the provisions if the provisions had continued? A. Correct. But it's now in our OM&A expenditure. Q. But it's now in your OM&A expenditure. Now, some of that sounds like it's work that couldn't have been done before 1997 or am I wrong in that respect? A. I suggest that you could re-engineer at any point in time. But if you're saying could we have re-engineered before 1997? Yes. We chose to re-engineer at this time as we've got a new organization and new models in place. Q. Okay. That sort of gives a reasonable description of the kinds of work that we're talking about. [Questioning] 470 Participants And if we can move on to, why was it considered appropriate on February 1998 to write these costs off to 1997 operations as a special provision, a special write-off? A. I think that Panel 1 spent quite a bit of time talking about this but I will try to restate some of what they described. In February of 1998 -- actually back in 1997, our Ontario Hydro Board had asked us to look at the condition of our system and to identify all costs that would be necessary to get our organization to a better condition and look across not just fixing assets but also redesigning processes that were necessary. There was a large nuclear element of this provision and a much smaller element across the rest of Ontario Hydro. It was at that time deemed appropriate to just identify all the costs and get the work established. We were very concerned about the statutory debt retirement and being able to fund these costs and still operate under the Power Corporation Act with the statutory debt requirement obligation. So the way to handle that was this special one-time provision. Q. Now, if I was looking at the books of the company or something - I'm not an accountant, right? - but it would seem to me very dodgy accounting to say, well, it's convenient for the statutory debt retirement to take some future costs and call them past costs. And it would seem to me that you would only have some legitimacy [Questioning] 471 Participants in doing that if you can say with your hand on your heart, 'These are properly the costs of past operations or the cost of fixing deficiencies in past operations rather than being regular costs of ongoing operations.' Is that a factor that came into that kind of rationale? A. I think the argument was one of having done an assessment of what processes and what condition of assets is appropriate - and we did do those assessments - what costs would it take in order to rectify the problem as it was assessed? So even though -- I think, Ken, are you very concerned about these process re-engineering ones; is that the nature of the question? Q. I'm concerned about all of them. A. Okay. Well, certainly the ones where the asset condition was identified as being below what our external parties recommended, those shouldn't be causing the concern from '97. I do have a greater sympathy for the process ones but even there the idea was that the industry standard practices in place in '97 were far superior than what we were using in Ontario Hydro and we should have the costs for those to get to industry best practice included in the provision. So that was the hand-on-the-heart reason why. Q. But it would seem to me that they have to be costs of past operations or fixing costs of deficiencies in past operations otherwise the accounts that you produce [Questioning] 472 Participants for your actual operations in 1998 are not properly reflecting the costs of operating the business in 1998 and the revenues and the profits that result from that are meaningless. A. Ken, I'd say that our characterization is, indeed, these costs relate to the charge to restore both processes and assets to a condition that was appropriate as of February of '98. They should have been there. They weren't but they should have been. Q. They should have been incurred prior to that date and that was why they were considered candidates for writing off? A. Right. Q. Thank you. Okay. Let's just leave that for a minute and we'll come back to that. MR. HARDY: Ken, I've jotted down three questions and I'm kind of waiting for the third one. MR. SNELSON: Q. I think we're coming to the third one. There's another element to this that has to be brought in and it's perhaps more efficient to deal with the two items together rather than separately. And that is that last night on reviewing some of this I came across what I think is another similar item but a different one and may be additional. And that's shown on page 133. And there's a discussion about the other post-employment benefits which were apparently written off on January the 1st, 1997. And in this section, the first [Questioning] 473 Participants paragraph on page 133 says: 'Since these amounts have not been previously recovered in rates, it's proposed that the OPEB past service liability be recovered in rates prospectively on a straight per line basis over a ten-year period.' MR. HARDY: Sorry, Ken, I'm going to have to get some help from you. This, I take it, is not page 133 of the main submission? MR. SNELSON: Yes, it is. It's page 133 of the main submission and the piece I've just read starts at line 4 in the middle of the paragraph. MR. HARDY: Okay. Thank you. MR. SNELSON: Okay. Q. And the first question is, there was a write-off according to this section, I think it's earlier in the section the reference to the write-off, on January the lst, 1997 for the costs of getting yourself onto an accrual basis for other post employment benefits; is that correct? MS. FRANK: A. Yes, I believe that was referred to just a couple of page prior to that where we talked about changing from a -- it's on 132 where we talk about changing the payment -- line 21 -- from a cash basis to an accrual basis and that was made. Q. And this is a separate and additional write-off to the one that was made in February, 1998? A. Yes, it is. [Questioning] 474 Participants Q. And how much of that was written off on January lst, 1997, that would be attributable to the transmission business or to the transmission and distribution business if you can give me both together? A. I am -- it's easier for me to go to actually the charge than the write-off that was made in January lst, 1998. I mean, I can talk to what's on the assets -- Q. It was January lst, 1997, I think. A. '7, I'm sorry, right. I can talk about what we're suggesting needs to be charged-- Q. Okay. A. -- into the ten year. There's $180-million worth of asset that we are suggesting should be amortized over a ten-year period meaning an $18-million charge per year, so you know, that's the amount that I think we're, you know, we are interested in. Q. Yes. And I think there was -- now, how I got the asset somewhere, but anyways, $18-million a year to the transmission business? A. Yeah. Q. There will be another charge similar but different to the distribution business? A. Right. Q. When did this depreciation of this asset start? Did it start in 1998, or if it was January lst, 1997, then it could even have started in '97? Or has it only just started in this -- in 1999? A. I believe it did start in 1997; $18-million [Questioning] 475 Participants per year. Q. $18-million per year? A. That's the amortization of this amount. Q. So this is not a reverse of the decision to amortize it over the life was taken at the time that the write-off was made? A. Yes, Ken, I want to reserve the ability to check that over lunch break, but that is my understanding. I will confirm, however. Q. Okay. Then to me, this has got some different aspects to the write-offs of the 1998 write-offs that we were talking about earlier? A. Yes, it's not the same animal. Q. Okay. So if it was established as an asset to be amortized over ten years at that time, then I presume that the Ontario Hydro Board of Directors used its power as the rate-making authority to set up a regulatory asset to recover these costs and amortize them over ten years? A. Yes, that's how I would characterize this, but once again, I will confirm that at the lunch break. Q. If you could, please. Okay. I think that brings us back to the third question which is relating to the 1998 asset write-offs and that is why they were written off. And we've established one of the reasons why they were written off and that is that they are catch-up costs for costs that in one way or another should have been [Questioning] 476 Participants incurred in years prior to the write-off and were not. It seems to me that there is another aspect to the write-off and that is that with respect to these costs, the Ontario Hydro Board of Directors did not exercise its power as the rate-making authority to set up a regulatory asset to recover these costs from customers and amortize them over a period of time in the way we've talked about with respect to the post-employment benefits; is that correct? A. That wasn't done, no. Q. That was not done. And I presume that was not done because the Ontario Hydro Board of Directors did not think that there was -- it was good policy or that it was possible to recover these costs from customers starting in 1998? A. Now Ken, I don't think I'd agree with that statement. I believe the decision when the write-off was taken in February of '98 was that these costs would be charged to equity and that the primary reason for that is that the charges couldn't be incorporated in the following years and still meet the statutory debt retirement so it had to be taken to equity. I believe that was the justification for charging it to equity. Q. Well, that's just another way, I think, of saying that if you had added it into the cost for customers, then you'd have had to go for a rate increase which you didn't want to do and the government said you shouldn't do? [Questioning] 477 Participants A. We certainly didn't want to go for a rate increase, I'll agree with that. Q. Okay. Now, the next question really is so there are costs that relate to past operating periods in one way or another. The Board of Directors of Ontario Hydro, for whatever reasons, chose not to try and recover the costs from customers. And the question is what has changed? Why have we now got people -- why are we now seeing this being brought back as a cost to be recovered from customers under the OEB's rate-making authority? A. When the business gets separated in April 1 of 1999, we get recapitalized, and we have talked about in Panel 1, on a 60/40 debt equity basis. And part of this recapitalization, the provision disappeared. It was no more. So if we wanted to go back and reinstate the provision, the way to do that, consistent with the past practice, would have been to write down our equity and not maintain a 60/40 consistent with the capitalization of its financial architecture. Consideration to that -- of that alternative was given; however, the financial risk of the corporation was going to change if we lowered our equity and that would affect the credit rating, the A crediting rating that Malen Ng discussed in Panel 1 and it was decided that was not an appropriate way to go. When we did further examination of what the costs are and the fact that we had never charged the customers for those costs, it seemed appropriate that these were [Questioning] 478 Participants costs that the customers received a benefit from us incurring, so we have added them in to our operating costs. Q. The provision just disappeared during the recapitalization? A. Yes, it did. Q. And now the provision, in a sense, is a an estimate of the cost required to bring your assets up to their normal expected condition, what you would consider to be an acceptable condition for them because of past under-spending or because of reengineering or whatever the explanation is that you've given us. Why wasn't that taken into account in the capitalization of the transmission company or assets? You have this provision there prior to the recapitalization, why wouldn't that have been carried forward? A. I believe these costs were now considered to be reasonable costs that we could charge to the customer in the new environment. Certainly the carrying forward of the provision was part of the conversations with the government on the architecture. I think Malen did make some, and Don Ariss made some mention of this in panel one. I don't believe I can go further. Q. And on a slight tangent here, but what we've effectively got here is that there was a write-off made, the management rate-making authority that was applicable at that time chose not to recover those costs from customers. And we now have an attempt being made to [Questioning] 479 Participants change that to recover those costs from customers and you have said that there are other jurisdictions that recover these types of costs. Do you know of any other jurisdiction where the costs were written off and then reinstated at a later date on a retroactive basis? A. I personally don't know of another example of that. Q. And we have said -- we've talked about the erosion of financial soundness and so on, and I think at page 139, line 21, you give the -- some or part of the rationale for reinstating these costs. Failure to recover the costs would result in expenditures having to be debt financed and would lead to erosion in the financial soundness of the transmission business. And my point here is that the write-off happened in the past, the erosion of financial soundness took place at that time, and what we -- we're are not actually trying to prevent erosion here of the financial soundness of the transmission business as much as we are trying to restore the value of the business by reversing past decisions. The erosion had already taken place in the past, that was real and had taken place. We are not just trying to prevent something here, we are trying to reinstate, we are trying to recover what had been done in the past. MR. HARDY: Ken, I'm wondering if I'm hearing some opinions stated here, and I'd just -- I'd sooner -- [Questioning] 480 Participants MR. SNELSON: Q. Well, I'm really asking for confirmation of what I've just said? MS. FRANK: A. There would be erosion of financial soundness at this point in time because the company was recapitalized or is being recapitalized, I should say, and with the separation of the new company on April 1, we have a new capital structure that is being proposed to be the 60/40 part of the financial architecture that we've talked about before. If we don't charge these costs to customer and we somehow change the cost by making a provision, our debt equity ratio will change and our financial soundness will deteriorate. Q. But the capitalization is not actually taking place. It is still possible to change some of those things. I think the actual recapitalization takes place on April the lst, next year. A. This year. Q. This year, sorry. I'm forgetting that we're in 1999 now. A. Certainly, there has been advice from financial advisors. I think Malen quoted all of the advisors involved in terms of 60/40 being appropriate debt equity ratio. And there's been -- I think, a lot of evidence provided suggesting that the capitalization that's in the submission is an appropriate capitalization. MR. HARDY: And I've heard the panel, I think, twice-- MR. SNELSON: Yes. [Questioning] 481 Participants MR. HARDY: --very cogently explain their position. I'm wondering if there's -- MR. SNELSON: Q. Well, I have one additional question in this area and that is that we have agreed, I believe, that these are costs that should have been incurred in 1997 and earlier years and they are now appearing not only in the OM&A requirement to be recovered from customers, but they are being imbedded in the base OM&A requirements of the transmission company. And even if these costs were proper to reinstate, they are still costs of previous years and would not -- wouldn't it be proper to identify them as special expenditures outside of the normal program in 1999 and 2000 so that they don't become part of the base of what is normal OM&A spending for performance base regulation types of issues and so on? A. That's actually exactly what we are doing is separating them out so that when you get to the next panel and they talk about a performance based type regulation and what's appropriate for the various factors, they will talk about Z factors that are one time or transitional type costs and the provision expenditures, that $59-million is treated as a one time cost and should not be in the base for performance measurement purposes. So we are doing just as you suggest, not indebting them. MR. SNELSON: Thank you. I'll leave it there for the moment. MR. HARDY: Thank you. Other questions from participants? [Questioning] 482 Participants MR. STEPHENSON: Yes, Richard Stephenson. Q. I just want to come back to this provision issue very briefly. My understanding is that in terms of taking the provision in '97, in terms of setting rates, that the Board, Ontario Hydro Board, was not bound by GAAP in terms of the accounting treatment of those rates, but they were operating under their authority in the PCA in taking that provision in '97; am I right about that? MS. FRANK: A. You're correct, they were not GAAP oriented provisions. Q. Right. So we shouldn't be looking around at GAAP to determine whether or not any of this was consistent with GAAP because it wasn't based on a GAAP based decision in the first place? A. Quite correct. Q. Okay. Secondly, in terms of your treatment of bringing these expenses back in, I've taken the financial architecture and Ms. Ng's description of it as more or less a given, but the government mandated you to set up a commercially viable, financially sound organization and the financial architecture that falls out of that is, in the judgment of you and your experts, is 60/40. I take it that that's more or less a given in terms of going forward to meet the government's expectation in terms of the type of business enterprise that's intended for the transmission -- or for the -- for SERVCO; is that fair? A. I'd agree with that. [Questioning] 483 Participants Q. And if you can't take these -- this provision on an ongoing basis and maintain that, it would be my understanding that, in essence, the only other alternative for these kind of costs is that it just goes into the residual stranded debt; isn't it? I mean, you couldn't take on this debt and maintain your financial soundness so it essentially goes to the residual stranded debt that's recovered through all the mechanisms that's used to recover residual stranded debt, isn't that -- isn't that the other alternative? If it doesn't go into your rate base, it just goes into the competition transition charge? A. There certainly was no suggestion that these costs could be part of stranded debt. Q. But let's put it this way. I mean, if you're -- you get an allocation in terms of recapitalization in terms of your assets and your liabilities, if the 60/40 is to be maintained and you can't take this in to maintain 60/40, it's got go somewhere else. And isn't one of the things that -- one of the alternatives is that the government simply could have not allocated this to you at all and maintained it as some form of residual stranded debt? Isn't -- I mean -- A. That was certainly not part of the discussions with the government. Q. Fair enough. But I mean, at least at some theoretical level, this is going to have to get picked up somewhere and it's either in your rate base or it's through some other recovery mechanism; isn't that fair? [Questioning] 484 Participants A. That's fair. We are suggesting it's in our rate base. Q. And I don't disagree with that. MR. STEPHENSON: Okay. Thank you. MR. HARDY: Okay. Any other participant questions? Okay. If we can turn now to Board Staff and -- oh, sorry. Go ahead. MR. WHITE (ECMI): Further supplemental, the same item. Q. The fact that that -- those dollars were not accepted by the government as part of the stranded debt, was that not an indication the government considered it inappropriate? MS. FRANK: A. No, I believe that was an indication the government thought it was appropriate the customers pay for it and that we could get it recovered through in rates, that's how I characterized it. MR. HARDY: Okay. I'm going to go to Board Consultants and Staff right now. Do you have any -- MS. BULKLEY (Reed): Q. I just wanted to briefly revisit the work programs, the sustaining work programs on page 141, line 3. In this table and in one of your subsequent filings you provided projections and you provided some historical data, the costs in these various categories, station's lines, telecommunications, and engineering and environmental support. [Questioning] 485 Board Staff/Consultants Can you give me a sense of whether the costs in these categories are expected to continue at the levels identified in the Year 2000 or will there be a drop-off after that? MR. DAVIES: A. I think if we go into the subset, for instance, table 9.4, which is on the same page, 141, I think I've indicated that the -- the contaminated lands, I can't forecast what the expenditures will be post-2000 until we've got a full assessment of the contamination or lack of contamination in all 256 sites. We are anticipating that we'll have to do remediation work in 1999 and Year 2000. Whether we'll complete that in those two years or whether there will be further expenditures required in subsequent years is really dependent on us getting the detailed sample results which are not available yet. So an optimist would say that we would see the contaminated lands program rapidly deteriorate -- rapidly reduce after that. A pessimist would say that it's a deterioration and we need to continue to spend a pile of money on remediation. So I think in that particular area, we're uncertain. In terms of remedial and component refurbishment, historically, the one major area there is mid-life overhaul of air blast breakers and I've covered that off. The program should be finished in 2000 except we have, I think, 12, 13 breakers to do in either 2003 or 2004. The other work that's in that area focuses [Questioning] 486 Board Staff/Consultants specifically on correcting known design deficiencies, this bridge issue and a few other things like that, and we're anticipating completing that by the end of Year 2000. The environmental management. Transformer re-gasketting, quite frankly, is an aging population of transformers. We anticipate that level of expenditure on an ongoing basis. A PCB phase-out should be completed in 2000, possibly a little bit into 2001, but a tail-down of the PCB refurbishment. Transformer radiator refurbishment, we're hoping to complete in the Year 2000. So the contaminated lands, remedial and environmental management, there are some ups and downs there and some uncertainties. The other programs we're expecting a similar level of expenditures in future years after the Year 2000. Q. Can you give me that same sense for the lines, telecommunications and engineering sections? A. Okay. The lines and cables and the rights-of-way, again, that shows unit efficiencies from the service provider, year 2000 over '99. That's a significant change in those areas and depending on the success of the service provider -- I'll make the assumption they're flat after the Year 2000, let's put it that way. Fixing known deficiencies should be completed by the Year 2000. [Questioning] 487 Board Staff/Consultants Removals is an ongoing issue, but I don't expect it to be the magnitude of a million dollars a year, perhaps somewhat less. ACA data collection, I expect to be completed in the Year 2000. If we turn to telecom, which I think is table 9.6 on page 148, the teleprotection, we're seeing a significant increase in '99 over '98 and quite frankly, that's the age end of life or beyond end of life of our microwave system. Our current plan is to replace it between now and 2005. Based on what we're seeing with the failure rate, we will be looking at accelerating that capital program to squeeze it sooner than the end of 2005 if it is practical from an outage point of view. While that -- sorry. Go ahead. Q. I just wanted to know if that was reflected in these numbers already? A. Yes. Q. That acceleration. A. Well, we're only looking at -- no, I don't expect the capital program to be accelerated beyond what we've shown in the two-year filing. In terms of the OM&A, I'm expecting the level of 13-million to continue to 2001, 2002. As we start getting these replacement facilities in service, I don't expect the level of maintenance on the teleprotections to be at that level and I expect it to go down. Other programs I expect it to be pretty flat. [Questioning] 488 Board Staff/Consultants Perhaps while we're at this, I wanted to put on the record an issue from yesterday on teleprotections. MR. HARDY: Sorry, okay. Then you'll move on to the -- there's another table, I believe, that... MR. DAVIES: Okay. I talked about yesterday why we've got a capital expenditure for replacing the microwave system; basically the end of life of a 30-years-old system that basically has a 15-year-old expected life. Another key issue is that the use of radio frequencies in Canada is regulated by the Federal Government. And in the past, we've had a -- all utilities have had a frequency band that we're allowed to use for utility use. Industry Canada, the licensing agency for the Federal Government, has reassigned frequency bands for utilities; has reduced the frequency band, has changed the frequency band for utilities. This change was effective January, 1999. We were required by regulation, by the federal regulation, to change our facilities to match the new federal band width. We have not met that intent. We have negotiated an extension with the Federal Government to 2005, I believe, allowing us to spread out our capital expenditures, to replace our microwave radios to suit the new frequency band that we and other utilities have been assigned. So, notwithstanding that this hardware is at end of life, if it hadn't been at end of life, we'd have [Questioning] 489 Board Staff/Consultants still had to make significant capital expenditures because of the Federal Government's relicensing of frequency bands for utilities. So I just wanted to put that on the record. MR. HARDY: Sorry, was there another table that you were going to speak to? MR. DAVIES: I don't think there was. I think I covered the three areas that I was asked to. MR. HARDY: Okay, thank you. MS. BULKLEY: Q. With regard to the engineering and environmental support and real estate services, could you tell me, how could the implementation of the asset management model change the requirements for engineering services going forward? MR. DAVIES: A. If anything, it may increase the requirements for engineering environmental services because it requires a pro-active forward-looking assessment of problems and issues and solutions. So these numbers reflect the funding for engineering support both from -- within OHSC, Myles' organization, and external consultants to support the asset manager in assessing alternatives and in assessing strategies, developing directive standards. So my expectation is with asset management, that, in fact, there is a need for more engineering analysis, not less. We've shown it flat or slightly reducing, the expectation of productivity improvements, from the service providers. [Questioning] 490 Board Staff/Consultants Real estate services reflects the administration of our land holdings. While we own a significant chunk of our rights-of-ways, we also have a large number of rights-of-ways, we have easement agreements with other landowners. In many cases, these easements are not forever. They come up for renewal on a periodic basis. And one of the costs incurred in the real estate group is to renegotiate easements at end of easement. We also have a secondary land use program as was mentioned earlier and the revenues from secondary land use are reflected in another table and these costs reflect our costs of generating that secondary land use. And as you can see, I think that there is -- well, perhaps you don't see, but there is a significant payback in terms of our costs versus our revenues from secondary land use. Q. Okay. MS. SIMMONS (Reed): I have another general question: Q. Very often in these types of proceedings we see a breakdown in O&M by labour and non-labour-related costs and I'm wondering, does such a breakdown exist and is that something that can be made available to the Board? MS. FRANK: A. I'm going to take to you the supplementary filing that we filed on January 4th-- Q. Okay. A. --filing J, and that is a resource breakdown that I think you were looking for and I suspect that Myles is prepared to talk to any questions you'd have on that. [Questioning] 491 Board Staff/Consultants MR. HARDY: This is on page 1 of J? MS. FRANK: (Nods). MS. SIMMONS: Q. We have it in total for all OM&A programs but not at the level that we -- you have presented your detailed programs by sustaining development, operations, et cetera, in the original filing. MS. FRANK: A. That's quite correct. Q. Okay. A couple other questions. I'm interested in understanding - you touched upon this morning - how the establishment of the IMO impacts -- how you're operating the grid. I mean, I understand you showed me a diagram yesterday on the transmission operations management centre. Are there activities that you were previously performing as part of your grid operations that the IMO is now taking on or has it simply created additional work in terms of information requirements that you may have to provide to the IMO? If you could just speak to that issue. MR. BARRIE: A. Well, of course, as we speak, negotiations are currently going on as to the precise nature of the relationship between the IMO and the OHSC in general and specifically in the operating domain for real-time operations, what the IMO will be doing and what the operators in the transmission company will be doing. At this point in time, it would seem that agreement is being reached, and I may be proved wrong on [Questioning] 492 Board Staff/Consultants this, but this is the understanding I have, is that there will actually be a very similar relationship to the relationship that currently exists within Ontario Hydro right now between the CMO that we have now and the operating staff that we have in terms of overall accountabilities. The IMO will take on accountability for directing the operation to ensure the integrity of the overall transmission grid. The transmission operators will carry out whatever operations are required. And as I indicated yesterday, the transmission operations management centre would inject the real-time asset management element, if you will, basically looking after the equipment. I think you, at this point, typified the final conclusion of this separation, is that there will be more data requirement. We will require ultimately our own data acquisition system to know what's going on on our system. The IMO currently has their own, the DACS system, DACS, Data Acquisition and Computer System, that's based at the system control centre at Clarkson. And our operators currently enjoy being able to feed from that and in future that may not be available to us. The reverse is also true, that the IMO does require information that our operators have. The current arrangement, by the way, in terms of overseeing is that the IMO really restricts its interest to the integrated transmission network, primarily the 500 kV and 230 kV. Looking after the 115 kV and below has [Questioning] 493 Board Staff/Consultants typically been done by my operators. We expect that to continue. So again, it's really just an extension of the existing arrangements. So I see some changes, but it's really just in terms of increased data, a separation, a more clear separation of the two accountabilities because after all, now we are in two different companies whereas today we're all part of Ontario Hydro. So we will have much clearer delineation of what each of us will do, whereas when you're all part of one company, maybe you just take some things for granted and you need not have it officially written down. That's really it. Q. Will there be transfers in operation staff or responsibilities between the two organizations; I mean, do you expect when the MDC makes their final report and final set of recommendations, that - we hope it ultimately will be approved by the Minister - that you'll have people who will move from your operations to the IMO or vice versa, from central market operations into your organization? A. If it transpires the way I just described, I would not expect that there would be any significant movement, in terms of overall resources. Individuals may move, of course, but that would be just normal movement between businesses where similar skills might be needed. But in terms of overall resources, I would not see significant movement between IMO and OHSC. Q. Okay. I'm going to switch topics. We [Questioning] 494 Board Staff/Consultants touched upon this morning the issue of recoverable work and I may ask similar questions to you of what my colleague asked this morning. You mentioned that work is performed pursuant to contracts in many, if not all, cases. And I'm just wondering, can you give us any indication of the term of these agreements, whether, you know, they've got evergreen provisions, whether they can be terminated unilaterally or bilaterally? MR. D'ARCEY: A. The majority of the contracts would be short-term in that work that we would do for a generating company or an external third party. Some of the work that is done is done under side agreements currently with the Genco business, okay, and those agreements are currently being formalized as to what services will be provided over the course of next year and we will look to see whether or not they are one-year, two-year or three-year terms. Q. Okay. When you charge work to third parties, you mentioned that you go through and you account for materials and labour and whatnot. I'm wondering if you can provide a bit more details as to how you charge for labour and whether that's the same way you charge yourself in terms of between transmission and distribution. Is it the same process regardless of whether you're working on a Genco facility or a distribution facility or a transmission facility, same internal rates, same allocation of resources? Or if there's something [Questioning] 495 Board Staff/Consultants different and if you can just indicate why that's the case on historical practice or something like that? A. No, there would be no difference between the two. The rates which we charge for work would be similar regardless of external, internal or between DNAM and TNAM. The only differences would be dependent upon the type of work that's being done and the associated equipment or tradespeople require to execute the work. But it's a standard rate for that typical type of work. Q. Okay. So regardless of whether someone spends one hour or three hours, it's all kind of built into it? I'm trying to understand that the rates for this recoverable work is no different from the rates for something else. It appears that there's a healthy amount of margin built into that and I would just like confirmation that it's not because of something that we're doing in reflecting the costs, i.e., someone spends an hour, they don't charge it to that project because seven hours of their day was spent on something else. It's all built into your accounting procedures that time spent on third party contracts is allocated and accounted for in the same method as it's charged to yourself? A. Each task, okay, is tracked and monitored and time is charged appropriate against that. And then we monitor that against the overall commitment and unit price in association with the delivery of that service. [Questioning] 496 Board Staff/Consultants So if we're set out to do a specific task it has a specific charge number or account which the employees will charge their time, equipment, material. So all the associated costs with executing that are allocated appropriately to the right account. MS. FRANK: A. Could I add, Susan, I think the profit is not quite as hefty as you might think. If you were looking at the total recoverable revenues for transmission in '99 and you saw a number like 67-million and then you looked at the total cost and saw a number like 49-million, that would imply a pretty hefty -- and that's likely what you saw. Q. It does. A. Okay. Well, the one factor that wasn't clear from those numbers is the item when I was talking about recoverable overhead costs. And that's $10-million for transmission in 1999 so the 67 goes down to 57 when you take off the amount of overheads associated with the OHSC functions and services that are recoverable from the non-regulated parts of the business. So now we're talking about 57 from 49. It's still a profitable business but not nearly as much so. And then the other thing in the 49 there are some activities - and I'll pick items like working on water heaters or sentinel lights or things like that where we've done our best to track those costs separately. I believe we have the majority of the costs in but I do have a bit of caution if we've been able to capture all of the costs. [Questioning] 497 Board Staff/Consultants Q. Okay. I think that helps clarify recoverable work. I have notes all over the place so I apologize if I'm jumping around from topic to topic. With respect to your recovery of the 180-million or 18-million a year of overhead expenses, I understand that was created because you switched from a pay as you go to an accrual method. Was that pursuant to a change in federal or accounting standards similar to that which happened in the United States? Or is that an internal decision that was made? A. No, indeed it is following the direction that happened in the United States where accrual method was adopted relatively recently for utilities and there are several utilities where the amortization of that cost is incorporated in their revenue requirement. Q. I may not have been clear in my question. Are you subject to FASBY regulations here in Canada or you're simply following something that occurred? A. We're following something that occurred. Q. Are you aware that other Canadian utilities, gas or electric, have adopted the accrual method for post-employment benefits similar to what you've done and is this consistent with those practices? A. We were not forced to adopt this practice at this time. It's something that we believe other utilities in Canada will be moving to. It certainly is very -- it [Questioning] 498 Board Staff/Consultants is used in the United States everywhere. If you're questioning could we have waited a year, possibly. Q. My next set of questions we've covered briefly and that's with respect to system losses in the transmission performance incentive. And I apologize if I'm asking you to state things that you've already stated but there is some amount of confusion with respect to this. So I'm just going to ask some basic questions and if you can answer them, that's great. If the answer is the Market Design Committee hasn't resolved this issue, then that's fine as well. But I just want to be clear under the proposed market design customers will be responsible for providing for their transmission losses? It's not being recovered through any sort of tariff; is that correct as best we know now? MR. BARRIE: A. Well, it's in the uplift so ultimately customers pay but that's the mechanism that's being proposed. Q. For now, for the transition until we move to location-based marginal pricing? A. That's my understanding. Q. And the uplift will be charged by the IMO to customers and if we didn't have the transmission performance incentive something would be tracked and accounted for completely separate from your business? [Questioning] 499 Board Staff/Consultants A. As I indicated within TPI there's sort of less than five per cent of the overall losses, so relating the two is a bit really confusing the issue. The vast majority of the losses have got nothing to do with TPI. Q. Right. But if we didn't have TPI, I guess my point is would the uplift charge be different or are these dollars simply a credit to the uplift charge which recovers an estimate of average system losses based on expected outages, expected generation dispatch and whatnot? A. I'm not sure what the impact on uplift would be, whether this was in or out to tell you the truth. Susan, do you know? MS. FRANK: A. No. Q. Okay. So when you referred previously that dollars would be flowing in and flowing out and you talked about payments, compensation to generators, are you directly compensating them or are you compensating them through the uplift charge which is then going to be redistributed? I'm just not sure where the dollars are flowing between the two? A. I think that there are three elements to the TPI and the direct payment to the generators was for the bottling element rather than the line loss element. Q. Okay. And then the line loss element -- okay, so a portion of it is going to generation, a portion [Questioning] 500 Board Staff/Consultants of it is going -- A. Back into the pool would be my suggestion during the transition period. Q. Okay. Are we going to have resolution of this issue anytime soon? I guess I'm just trying to understand -- it just seems like dollars associated with losses are not clearly tracked through and I do follow that you can -- you're telling me you can identify incremental losses as a result of transmission outages different from average system losses but I have nowhere where I can reconcile. This study shows me they're not being recovered through the uplift charge and I'm wondering whether there's anything you can do or provide to me that will give me a better understanding on this issue and on this topic to help me better evaluate the transmission performance incentive that's asked for in this filing? MR. BARRIE: A. Well, I think the whole treatment of this TPI will be gone into in some detail, its application, in Panel 4 when they look at performance-based rate-making. At least I've been assured of that. MR. HARDY: So I'm assuming that that will come forward in a future panel then? MR. HARPER: I think we can see what we can do between Panel 4 which is considering the performance-based rate-making and also Panel 5 which will be dealing with the rates. I think there will be an element there as [Questioning] 501 Board Staff/Consultants well. MR. HARDY: Okay. Thank you. Can I just get some sense of how long this set of questions is going to be so I can judge the time? Another half hour, so we're going to try to continue to twelve-thirty and see if we can stand down around that period. So have our indulgence for that time and I will be returning to participants to see if there are any other questions that are arising from here but that seems like a fair target. So why don't you continue, Susan? MS. SIMMONS: Q. I'm thinking that what would really help me understand this is that 23-million is calculated in some way, somehow, either as something -- you've told me 6-million that's going to the generator, something to do with incremental losses. How much -- and you've told me it's about five per cent of the total but I don't know what you've used for the cost of those losses and the level of losses versus whatever is going to be recovered, average system losses, via the IMO. And I'm wondering whether there's any sort of work paper that shows me that you've determined these are incremental and they're not system and something that would show the netting out of those and the recovery via this mechanism and not being recovered through the IMO or recovered through the IMO and this being credited back in [Questioning] 502 Board Staff/Consultants terms of total revenues to that uplift charge? Does anything like that exist? MR. BARRIE: A. I think what we can undertake to do is to have look at the specifics that were in TPI, precisely what you're asking for, like how much of the losses were put in there and how were they valued on a per megawatt hour basis. The more difficult thing that I'm struggling with is relating that to the big picture that the IMO is dealing with because that is still under debate. So I can certainly help you with the first part of it. The second part I'll have to see what I can do. MR. HARDY: I'll note that as some information to come forward. MR. BARRIE: Right. And on the first one I know I do have information on the specifics of the 23-million in TPI and in particular how the losses were calculated and what part of the overall losses that covers. MR. HARDY: Thank you. MS. SIMMONS: Q. Okay. That would be helpful and we can always pursue the uplift charge through other mechanisms which may be more appropriate. Can you just tell me how -- go through it again, you talked about these incremental losses as a result of transmission outages. Why is this appropriate for a performance incentive? How can you change what you're doing? And why is this a reasonable measure for performance incentive versus something else? [Questioning] 503 Board Staff/Consultants A. It's fair to say that virtually all of the performance measures that -- the parts of the TPI would all really relate to shall we say short-term decision-making. It certainly drives actions of the operating staff. One could debate whether it has any real impact on the overall asset management and the planning and the maintenance but it certainly does have an impact on operating. If I could just quickly give an example, it does drive operating staff to optimize when you have outages to start with so that you have your outage program so that it has minimum effect on generators. Then having agreed you're going to have an outage, it also encourages you to shorten that outage to the maximum extent possible. So actually it does impact the people actually doing the work as well. It may well be that Myles might have a certain number of staff working on a particular outage and if there are significant system costs involved because of that outage, it may well drive us as asset managers to ask Myles to work overtime, to put more resources on so that what was a ten-day outage is reduced to seven days and thereby we save three days. So it does impact the actual short-term operations and the carrying out of work. That would impact both any outage which caused constraints on the system, any bottling of generation. And it also impacts [Questioning] 504 Board Staff/Consultants any outage which increases system losses which is virtually every outage by the way. Not all outages cause constraints on the generators but almost all outages would tend to increase system losses because it increases flows on parallel circuits. Q. If you have a higher than expected number of outages or your forced outage rate increases under this mechanism would you as a transmission provider absorb the costs of those increased losses? A. That's the intent of it, both forced and planned outages by the way. Any outages which cause any constraint we're being driven to minimize those costs. Yes, that's the intent of it. Q. Have you done any sort of studies in terms of -- I mean you gave the example ten days, seven days where you've seen that it has an impact. It sounds like in deciding this somewhere someone made a decision that we have control over these losses and we can save this amount of money and X amount of money. Has there been any sort of historical studies that you've done to support this element of the performance incentive mechanism? A. Well, we have -- we have about three years of actual experience with this where we have looked at what -- what we actually achieved in any given year in terms of minimizing both the losses we have some influence on and the constraints that we have caused. So we do have that. [Questioning] 505 Board Staff/Consultants Is that -- is that what you had in mind or -- Q. Just some indication as to how much -- you've asked for 23-million, but if you can save 20-million because you're -- you're changing something, then maybe this isn't the performance incentive mechanism, maybe -- maybe you should just be doing those things in the first place. And that's what, you know, I'm trying to understand is, you know, why this performance incentive mechanism, you told me in some cases we're going to have to staff up and possibly work some overtime, so there's a trade off there. A. Right. Q. You know, versus alls we have to do is reschedule something from the second week in May to the third week in April and, you know, we save 10-million. Those are -- if you can just give me some anecdotal or some general background with respect to that. That it's, you know, we think we can save maybe eke out 5-million by doing some extra overtime or to, you know, our study shows we can save 20-million and that goes right into our pocket? A. Well, there's only a total of 23-million altogether-- Q. Right. A. --in there, so our ability to -- it's assumed, first of all, that we put together an outage program, we develop an annual outage program and then we have a short term outage program which looks two months. [Questioning] 506 Board Staff/Consultants So the first one we have is an overview of the whole year, and then as we get closer to of actual period, we have a very, very specific outage program. And that outage program is tightly linked to any generator outage program. And the whole idea, of course, is to match the two so that we don't cause any constraints. So as you rightly say, there are a lot of things that we should just be doing anyway and we do. Nevertheless, by looking back historically, we've looked -- we have been able to identify that it's not always possible to do that, but occasionally, unfortunately, we have to take an outage that does cause some generator constraint. Now, whether it's a reasonable number or not was based on history. We looked back and saw basically what we had been able to achieve in the past and thereby simply set ourselves a bar, if you will, where we were trying to improve on. So whether the number is appropriate or not, I think we have to just look at history. But that's the kind of number involved. In terms of outages, you'd be looking at the order of 6 or $7-million, the same as the losses because the total, as I said, only comes to 23-million. Whether this actual TPI is a good performance measure or not, I think you should reserve judgment on. I think it's -- all we're trying to do by putting TPI in at this point is to indicate the kinds of things that we [Questioning] 507 Board Staff/Consultants believe are good drivers for a transmission company which is basically anything that the customer says. And in this context, I'm including generators as customers of the transmission system. So as far as a generator is concerned, the most important thing as far as he's concerned is, first of all, that his connection with the transmission is reliable. And the second thing is probably that he does not have any constraints in getting his product to market. So those are the kinds of drivers that we believe should be imposed upon us in any performance based rate-making. But hanging my hat too closely on what's on TPI, that is not what I had intended to do. MR. HARDY: James, you had a question? MR. WHITEMAN (Board Staff): Q. Just clarify for me if you would then, that there isn't an exact mechanism set up to determine a performance incentive, this 23 or 24-million; is that right? Like normally a performance incentive, the better you do -- MR. BARRIE: A. Yeah. Q. -- the better off you are? A. Right. Q. So where did the 23 come from? How did we get that number, the 23-million? A. We looked back over some period of time. Q. Yeah. A. Three or four years, and we looked at how [Questioning] 508 Board Staff/Consultants much our actions actually caused constraints on the system or increased system losses which seems to be the two examples we are homing in on. And based on that historical performance, we are suggesting that's where you set the bar, and the idea is to do better than that. Q. Okay. And just one more thing, do you have any -- are up relatively self-assured, I should say, that the benefits of this program to the customers and all your clients will exceed that 23-million? A. Well, it's the actual cost that -- in the case of the constraints, for instance, it's the actual costs that the generator -- at the time, it was only one generating company, so to take that particular example, if we were to bottle nuclear generation, our own nuclear generation, when -- speaking as ours has been Ontario as one company at the moment, and because of that, we were forced to run some fossil generation. The difference in marginal cost for those -- between those two, let's say for the sake of argument, is about $20 a megawatt hour. So for every megawatt hour that we bottled of that nuclear generation, we would pay the difference, the difference in the two marginal costs. That's how it was calculated. Now, in an open market when you have lots of different generators, the same principle, I think, is a reasonable one to apply. If generator A cannot get product to market, of course, they should be recompensed for that. Now, what's in the performance based rate-making, [Questioning] 509 Board Staff/Consultants how that will work with multiple generators, I'm not sure. But the principle is still the same. Q. Okay. I guess I was just trying to satisfy myself that -- that the customers would be better off as a result of this program? A. In this particular case, the way we applied it, it was actually neutral to the -- to the end customer because the wins and losses of the two generators we were putting into the pot. So yes, it was neutral. Q. Yeah, so that they would be indifferent -- A. Right. Q. -- the customers. MR. WHITEMAN: Okay. That's it. MR. HARDY: Any other questions from our Board staff? MS. WALLI (Board Staff): Yes, just two follow up questions, actually. Q. Going back, Susan, to when you were discussing your financial analysis for new programs, you mentioned you used net present value techniques. Do you, as a matter of interest, also use internal rate of return as a criteria? MS. FRANK: A. That information will normally be available to the decision makers, yes. Q. And what, for example, are your hurdle rates? A. We don't have -- I don't have a current set of hurdle rates for this -- this new business. Q. So that's not been carried forward from the [Questioning] 510 Board Staff/Consultants previous Ontario Hydro, so to speak? A. No, what we're -- every year in our use of the net present value analysis, and we don't have new hurdle rates. Q. Do you see, for example, using, if for example, you do set new hurdle rates for OHSC, do you see using differential hurdle rates for whether you're employing new technologies versus tried and true technologies? A. I'd agreed in principle that that's a good approach to do because the risk differential between this work, but as I say, we don't have hurdle rates in place at this time so I can't say that we are doing it. Q. So currently you'll be focussing primarily on net present value techniques solely? A. Right. Q. Thank you. A final follow up question, actually. Last week Ms. Ng was talking on a cost of capital issue and had indicated Ms. McShane, Kathy McShane would be providing a more detailed report in follow up to her letter to Mr. Taylor which is found in Appendix U of the main filing. I think last week Ms. Ng indicated we'd be getting that report. It was in the process of being finalized within about a week or so. Do you have an update on that? A. Actually I'll ask -- MR. HARPER: I think we expect that to be the [Questioning] 511 Board Staff/Consultants timing. I know when we went back, the report had not been finalized and she had to do some further work on it and our expectation is that it would be probably around the end of this week or early next week it will be filed. MS. WALLI: So for example, we could expect to see the report to, not only ourselves, but obviously all stake holders, shall we say, prior to next Monday, or certainly prior to the end of these current proceedings? MR. HARPER: It will be definitely prior to the end of the proceedings and early next week at the latest, yes. MS. WALLI: Thank you. Those are my questions. MR. HARDY: Participant, any final participant questions? MR. BACON: Bruce Bacon for OCAP. Q. One question of clarification on this -- this TPI. It's a principle question, really. If we actually moved to locational marginal pricing, would TPI disappear? MR. BARRIE: A. I don't think so. I think the transmission company should still have drivers to -- to the maximum extent it can have its equipment available. What the locational based marginal pricing will do, of course, will highlight when we are not doing that because we would -- it would tend to make a bigger spread in the prices. The more -- the more we have available and the more we can make the market work, the more likely it is that prices would tend to be more even across the [Questioning] 512 Participants province. So I don't think it makes it disappear. MR. BACON: Okay. Thank you. MR. HARDY: Thanks. Roger? MR. WHITE: It's Roger White, ECMI again. Q. I have a couple of questions relating to recoverable work. Currently, there are a telecommunication interconnections with customer owned stations. Under historical relationships, the customer typically maintained the facilities at their station, Ontario Hydro typically maintained the facilities at its stations. In light of the unbundling of energy, has that practice been revisited, and if so, is there any expected change in the allocation of costs, either directly to customers or a continuance of the existing practice? That's the first part. MR. BARRIE: A. Just a moment. MR. DAVIES: A. I think we're going to have to take it under advisement rather than definitively saying. Q. If you're going to go back and look at it, can I ask that you also include an assessment as to whether high voltage DSs, and I still haven't figured out whether -- whether they belong where they are in terms of the new structure, but whether the charges to Disco are being treated in a similar fashion as they would have been to end-use customers or municipal utilities in such situations? A. Can I ask you just to restate your first question so I clearly understand it. [Questioning] 513 Participants Q. The simple obvious answer relates to -- or question relates to the telecommunication because it's a little -- it's the cleanest probably of the packages of unusual interface relationships that exist. And in those cases, historically, under contract, say, direct industrial customers would have a protection system which may block some of our -- some of Ontario Hydro's normal line interrupting capability to give the customer station protection an opportunity to operate or may, in fact, activate it to give the station equipment a chance to operate. It's because the station is located primarily on a system of where the available short is incredibly high and it's not cost effective to put in line breakers to deal with customer station protection. In those cases, telecommunication is used to change the way the protection scheme operates in a similar way to if Ontario Hydro were to put in such a station. Traditionally, the customer has paid for the maintenance of the facilities at their station and Ontario Hydro has paid for the maintenance of the facilities at its own station, so I'm assuming that Transco is picking up those responsibilities with respect to what would have been formerly Ontario Hydro's facilities and the customer is picking up -- or continuing to bear their share and the telecommunications in between are often owned -- or paid for by the end use customer. What I'm questioning is, is that practice [Questioning] 514 Participants continuing, does it remain appropriate in terms of having it continue and is the same policy applying to the distribution division or wing of SERVCO? MR. BARRIE: A. Okay. Well, with that clarification, I think I can at least attempt an answer. The communication you're speaking about is related to the protection of the transmission facilities feeding the customer and as such, it would be appropriate for any such arrangement to be transferred to the transmission company, yes. So the answer to your first question is yes. You did the first time you phrased the question start speaking about energy provision as well which is not part of the transmission company. So if it's purely about the protection of the line, it's certainly appropriate that that be transferred at the transmission company and I would expect that the arrangement that we have right now will continue in the future. I think I said earlier that in at least the model I have for the transmission company, our distribution company is exactly the same as a municipality and so I would expect the same arrangement. Q. So in that case, we can expect to see Disco having those costs of maintaining its facilities at its end in its budgets? A. The other distribution companies should have its telecommunication costs. You didn't actually ask a question about DSs, but you made an aside which I'd like to respond to. [Questioning] 515 Participants Q. Okay. A. You said you didn't know where DSs belong. DSs belong in the distribution system. And, in fact, in appendix L of the supplementary filing dated 4th of January, we did go to some length to explain that we did do an asset boundary assessment sometime ago because there were some anomalies with the DSs and we wanted to clear that up and so all DSs are part of the distribution system. Q. My comment and question, I guess, or side comment related to the high voltage DSs which I'm sure you're familiar with-- A. Yes. Q. --and -- A. That's what I was referring to. Q. Was that evaluation done on the basis of functionality; and if so, what criteria were used to establish the functionality? Are those in that appendix? A. Yes, it was done on functionality and the criteria are specifically laid out in the appendix I just referred to. MR. HARDY: Roger, are you finished? Are there any other questions from participants? Susan? MS. SIMMONS (Reed): I have one more brief cost study just going through my notes. Q. One of the comments you made either yesterday or today with regard to your environmental activities and [Questioning] 516 Board Staff/Consultants you referred to, you know, being an environmental steward and I guess I just have a question and I'd like someone to kind of comment back. When we talk about companies being environmental stewards, usually we're talking about people who are in a four-profit situation where their activities impact their bottom line. But here I see there's a lot of environmental activities. Some are in response to environmental requirements under the law. Some are in response to what you're doing. And everything that's being done is being asked for for recovery in rates, so I'm just trying to understand, if you could, please, comment with respect to -- you're doing things because you think it's appropriate, but yet, ratepayers end up paying for it. Where is the balance being made and how far? And specifically with respect to the contaminated lands, are any of those contaminations as a result of improper activities by your staff or were any ones that liability can be assigned? MR. DAVIES: A. We believe that the staff at the time and we, as a company, over the last 90 years were following the law at that time. Obviously the environmental regulations evolve over the last 90 years, so what was appropriate 50 years ago may not be appropriate today. Q. Okay. A. I'd make one comment on the contaminated [Questioning] 517 Board Staff/Consultants lands issue, that the provincial government gave a specific directive to Ontario Hydro to do a detailed land contamination study and remediation for its generation sites, generation station sites. Ontario Hydro's senior management decided that it would be appropriate to extend that direction - I'll call it a voluntary decision - to not only look very closely at all its generating station lands but also look at all lands that it owned, all transmission station, s distribution stations, service centre stations, so characterizes as within the intent of the provincial government direction even though the specific direction at the time was just generation sites. Q. And how do you balance the decision to pursue or exceed environmental standards? You made this decision because you said in one case it was influenced by provincial interests with respect to the generation sites. Is it simply at the prodding of someone else that you're pursuing environmental remediation or is it something that you're doing that you think overall in the long run, i.e., a potential change in future, environmental regulations, it's appropriate to do these activities now and seek recovery from your customers? It's more of a policy question I think. MR. BARRIE: A. Yes. When we do something beyond the strict regulatory requirement, I think we're -- we're doing risk management really. It may well be that that additional step we took beyond what the strict law of the land requires us to do is because we believe that if [Questioning] 518 Board Staff/Consultants we don't do that, there might be serious repercussions down the road and that's particularly true of all of our sites that we're looking at. If it transpires that because of that we identify some contamination and we're able to do it early, we can prevent such contamination getting off site. So I believe it's part of the overall risk management that we do as an asset owner that I think every asset owner does actually. Q. And one final question: To the extent any of that contamination or environmental conditions was a result of problems with manufacturing equipment, has Ontario Hydro or SERVCO as this new independent organization sought to pursue any of those issues with the manufacturers of your equipment? A. I don't believe we have at this point in time, but Tim might know. MR. DAVIES: A. No, I don't think so and I'm not sure how viable it is to go back to entities from 60 or 70 years ago. Those particular commercial entities in many cases don't exist anymore. Q. And nothing is covered under existing insurance policies where you could seek any sort of actions under those? A. I don't believe so. MR. HARDY: Thank you. Is there anybody who wished to ask a question who hasn't had an opportunity? - --(No response) Seeing nobody, are there any other comments that [Questioning] 519 Board Staff/Consultants the panel wish to make before we break? MS. FRANK: Yes. I'd like to make one correction to an answer that I gave to Ken on OPB. I had suggested that we started the amortization in 1997 and I was incorrect. The amortization did not start until 1999. That's when the asset was first established. The liability was created in 1997 but no asset. The asset was not create until this year when we went through the capitalization process. And my understanding is, it's by looking at American practice with this asset that it is common practice that past employment benefit costs are amortized and charged to the customer, that that's when we established it, so I apologize for my previous error. MR. SNELSON: Okay. Just so that we're clear here, this is another example of choosing to charge this, charge a past cost to customers in this application which was not done by the Ontario Hydro board of directors under the previous regime? MS. FRANK: A. It was -- certainly the liability was created back in 1997 without creating the asset. And upon capitalizing our business, it was recognized that a more common treatment for OPB was to also create the asset and to amortize it to customers. So yes, it was a change. MR. HARDY: Thank you. That completes the work of this panel. I understand that the transcripts are on their way to becoming on the web page for the Board, so if you wish to access them, you can hit the Board web page. 520 That completes this part of the rates discussion with respect to transmission until Monday. We reconvene then and we will be discussing the transmission PBR proposal in some depth on Monday. So we'll see you then. Thank you for your participation. And thank you, panel. ---Whereupon, the Technical Conference proceedings were adjourned at 12:31 p.m., to be reconvened on Monday, the 18th day of January, 1999, at 9:00 a.m. 521 I N D E X o f P R O C E E D I N G S Page No. Overview (Facilitator) 408-410 Introductions 409 PRESENTATION: by Dave Barrie 411-416 by Susan Frank 416-418 QUESTIONING: by Consultants and Board Staff 419-447 by Participants 448-484 by Consultants and Board Staff 484-511 by Participants 511-515 by Consultants and Board Staff 515-520 Parties who questioned: B. Bacon . . . . . . . . . . . OCAP R. Stephenson . . . . . . . . Power Workers' Union R. White . . . . . . . . . . Energy Cost Management Incorporated JB/LJ/LL [ Copyright 1985].